Central Coast Community Energy (3CE) Operations Board
November 12, 2025

EXECUTION VERSION
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ARTICLE NINE: GOVERNMENTAL CHARGES

9.1 Cooperation. Each Party shall use reasonable efforts to implement the provisions of and to administer this Master Agreement in accordance with the intent of the parties to minimize all taxes , so long as neither Party is materially adversely affected by such efforts.

9.2 Governmental Charges. Seller shall pay or cause to be paid all taxes imposed by any government authority(“Governmental Charges”) on or with respect to the Product or a Transaction arising prior to the Delivery Point. Buyer shall pay or cause to be paid all Governmental Charges on or with respect to the Product or a Transaction at and from the Delivery Point (other than ad valorem, franchise or income taxes which are related to the sale of the Product and are, therefore, the responsibility of the Seller). In the event Seller is required by law or regulation to remit or pay Governmental Charges which are Buyer’s responsibility hereunder, Buyer shall promptly reimburse Seller for such Governmental Charges. If Buyer is required by law or regulation to remit or pay Governmental Charges which are Seller’s responsibility hereunder, Buyer may deduct the amount of any such Governmental Charges from the sums due to Seller under Article 6 of this Agreement. Nothing shall obligate or cause a Party to pay or be liable to pay any Governmental Charges for which it is exempt under the law.

ARTICLE TEN: MISCELLANEOUS

10.1 Term of Master Agreement. The term of this Master Agreement shall commence on the Effective Date and shall remain in effect until terminated by either Party upon (thirty) 30 days’ prior written notice; provided, however, that such termination shall not affect or excuse the performance of either Party under any provision of this Master Agreement that by its terms survives any such termination and, provided further, that this Master Agreement and any other documents executed and delivered hereunder shall remain in effect with respect to the Transaction(s) entered into prior to the effective date of such termination until both Parties have fulfilled all of their obligations with respect to such Transaction(s), or such Transaction(s) that have been terminated under Section 5.2 of this Agreement.

10.2 Representations and Warranties. On the Effective Date and the date of entering into each Transaction, each Party represents and warrants to the other Party that:
(i) it is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation;
(ii) it has all regulatory authorizations necessary for it to legally perform its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);
(iii) the execution, delivery and performance of this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) are within its powers, have been duly authorized by all necessary action and do not violate any of the terms and conditions in its governing documents, any contracts to which it is a party or any law, rule, regulation, order or the like applicable to it; (iv) this Master Agreement, each Transaction (including any Confirmation accepted in accordance with Section 2.3), and each other document executed and delivered in accordance with this Master Agreement constitutes its legally valid and binding obligation enforceable against it in accordance with its terms; subject to any Equitable Defenses;

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(v) it is not Bankrupt and there are no proceedings pending or being contemplated by it or, to its knowledge, threatened against it which would result in it being or becoming Bankrupt;
(vi) there is not pending or, to its knowledge, threatened against it or any of its Affiliates any legal proceedings that could materially adversely affect its ability to perform its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);
(vii) no Event of Default or Potential Event of Default with respect to it has occurred and is continuing and no such event or circumstance would occur as a result of its entering into or performing its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3); (viii) it is acting for its own account, has made its own independent decision to enter into this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) and as to whether this Master Agreement and each such Transaction (including any Confirmation accepted in accordance with Section

2.3) is appropriate or proper for it based upon its own judgment, is not relying upon the advice or recommendations of the other Party in so doing, and is capable of assessing the merits of and understanding, and understands and accepts, the terms, conditions and risks of this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);
(ix) it is a “forward contract merchant” within the meaning of the United States Bankruptcy Code;
(x) it has entered into this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) in connection with the conduct of its business and it has the capacity or ability to make or take delivery of all Products referred to in the Transaction to which it is a Party; (xi) with respect to each Transaction (including any Confirmation accepted in accordance with Section 2.3) involving the purchase or sale of a Product or an Option, it is a producer, processor, commercial user or merchant handling the Product, and it is entering into such Transaction for purposes related to its business as such; and (xii) the material economic terms of each Transaction are subject to individual negotiation by the Parties.

10.3 Title and Risk of Loss. Title to and risk of loss related to the Product shall transfer from Seller to Buyer at the Delivery Point. Seller warrants that it will deliver to Buyer the Quantity of the Product free and clear of all liens, security interests, claims and encumbrances or any interest therein or thereto by any person arising prior to the Delivery Point.

10.4 Indemnity. Each Party shall indemnify, defend and hold harmless the other Party from and against any Claims arising from or out of any event, circumstance, act or incident first occurring or existing during the period when control and title to Product is vested in such Party as provided in Section 10.3. Each

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Party shall indemnify, defend and hold harmless the other Party against any Governmental Charges for which such Party is responsible under Article Nine.

10.5 Assignment. Neither Party shall assign this Agreement or its rights hereunder without the prior written consent of the other Party, which consent may be withheld in the exercise of its sole discretion; provided, however, either Party may, without the consent of the other Party (and without relieving itself from liability hereunder), (i) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements, (ii) transfer or assign this Agreement to an affiliate of such Party which affiliate’s creditworthiness is equal to or higher than that of such Party, or (iii) transfer or assign this Agreement to any person or entity succeeding to all or substantially all of the assets whose creditworthiness is equal to or higher than that of such Party; provided, however, that in each such case, any such assignee shall agree in writing to be bound by the terms and conditions hereof and so long as the transferring Party delivers such tax and enforceability assurance as the non-transferring Party may reasonably request.

10.6 Governing Law. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE

PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED, ENFORCED AND

PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. EACH PARTY WAIVES ITS RESPECTIVE

RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY LITIGATION ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT.

10.7 Notices. All notices, requests, statements or payments shall be made as specified in the Cover Sheet. Notices (other than scheduling requests) shall, unless otherwise specified herein, be in writing and may be delivered by hand delivery, United States mail, overnight courier service or facsimile. Notice by facsimile or hand delivery shall be effective at the close of business on the day actually received, if received during business hours on a Business Day, and otherwise shall be effective at the close of business on the next Business Day. Notice by overnight United States mail or courier shall be effective on the next Business Day after it was sent. A Party may change its addresses by providing notice of same in accordance herewith.

10.8 General. This Master Agreement (including the exhibits, schedules and any written supplements hereto), the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any Confirmation accepted in accordance with Section 2.3) constitute the entire agreement between the Parties relating to the subject matter. Notwithstanding the foregoing, any collateral, credit support or margin agreement or similar arrangement between the Parties shall, upon designation by the Parties, be deemed part of this Agreement and shall be incorporated herein by reference. This Agreement shall be considered for all purposes as prepared through the joint efforts of the parties and shall not be construed against one party or the other as a result of the preparation, substitution, submission or other event of negotiation, drafting or execution hereof. Except to the extent herein provided for, no amendment or modification to this Master Agreement shall be enforceable unless reduced to writing and executed by both Parties. Each Party agrees if it seeks to amend any applicable wholesale power sales tariff during the term of this Agreement, such amendment will not in any way affect outstanding Transactions under this Agreement without the prior written consent of the other Party. Each Party further agrees that it will not assert, or defend itself, on the basis that any applicable tariff is inconsistent with this Agreement. This Agreement shall not impart any rights enforceable by any third party (other than a permitted successor or assignee bound to this Agreement). Waiver by a Party of any default by the other Party shall not be construed as a waiver of any other default. Any provision declared or rendered unlawful by any applicable court of law or regulatory agency or deemed unlawful because of a statutory change (individually or collectively, such events referred to as “Regulatory Event”) will not otherwise affect the remaining lawful obligations that arise under this Agreement; and provided, further, that

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if a Regulatory Event occurs, the Parties shall use their best efforts to reform this Agreement in order to give effect to the original intention of the Parties. The term “including” when used in this Agreement shall be by way of example only and shall not be considered in any way to be in limitation. The headings used herein are for convenience and reference purposes only. All indemnity and audit rights shall survive the termination of this Agreement for twelve (12) months. This Agreement shall be binding on each Party’s successors and permitted assigns.

10.9 Audit. Each Party has the right, at its sole expense and during normal working hours, to examine the records of the other Party to the extent reasonably necessary to verify the accuracy of any statement, charge or computation made pursuant to this Master Agreement. If requested, a Party shall provide to the other Party statements evidencing the Quantity delivered at the Delivery Point. If any such examination reveals any inaccuracy in any statement, the necessary adjustments in such statement and the paymentsthereof will be made promptly and shall bear interest calculated at the Interest Rate from the date the overpayment or underpayment was made until paid; provided, however, that no adjustment for any statement or payment will be made unless objection to the accuracy thereof was made prior to the lapse of twelve (12) months from the rendition thereof, and thereafter any objection shall be deemed waived.

10.10 Forward Contract. The Parties acknowledge and agree that all Transactions constitute “forward contracts” within the meaning of the United States Bankruptcy Code.

10.11 Confidentiality. If the Parties have elected on the Cover Sheet to make this Section 10.11 applicable to this Master Agreement, neither Party shall disclose the terms or conditions of a Transaction under this Master Agreement to a third party (other than the Party’s employees, lenders, counsel, accountants or advisors who have a need to know such information and have agreed to keep such terms confidential) except in order to comply with any applicable law, regulation, or any exchange, control area or independent system operator rule or in connection with any court or regulatory proceeding; provided, however, each Party shall, to the extent practicable, use reasonable efforts to prevent or limit the disclosure. The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, this confidentiality obligation.

EXECUTION VERSION
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SCHEDULE M
(THIS SCHEDULE IS INCLUDED IF THE APPROPRIATE BOX ON THE COVER

SHEET IS MARKED INDICATING A PARTY IS A GOVERNMENTAL ENTITY OR

PUBLIC POWER SYSTEM)
A. The Parties agree to add the following definitions in Article One. “Act” the Joint Exercise of Powers Act of the State of California (Government Code Section 6500, et seq.).
“Collateral Agent” has the meaning in the Security Documents. “Depositary Bank” has the meaning in the Security Documents. “Intercreditor and Collateral Agency Agreement” means the Intercreditor and Collateral Agency Agreement, among the Collateral Agent, Party A, Party B and the PPA Providers party thereto from time to time.
“Secured Account” means the Lockbox Account (as defined in the Security Agreement).
“Secured Creditors” means each PPA Provider that is a party to the Intercreditor and Collateral Agency Agreement and its respective successors and assigns.
“Security Agreement” means the Security Agreement, between Party B and Collateral Agent, as collateral agent for the benefit of the Secured Creditors.
“Security Documents” means, collectively, the Intercreditor and Collateral Agency Agreement, the Security Agreement, the Account Control Agreement entered into by the Parties and certain third parties in connection with a Transaction, and any other agreement or instrument documenting the security of Party A in connection with a Transaction, as the same may be amended, restated, modified, replaced, extended, or supplemented from time to time.
“Special Fund” means the Secured Account, which is set aside and pledged to satisfy Party B’s obligations hereunder and out of which amounts shall be paid to satisfy all of Party B’s obligations under this Master Agreement for the entire Delivery Period.

B. The following sentence shall be added to the end of the definition of “Force Majeure” in Article One.

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If the Claiming Party is Party B, Force Majeure does not include any action taken by, or any omission or failure to act of, Party B in its governmental capacity.

C. The Parties agree to add the following representations and warranties to Section 10.2:

Party B represents and warrants to Party A continuing throughout the term of this Master Agreement, with respect to this Master Agreement and each Transaction, as follows: (i) all acts necessary to the valid execution, delivery and performance of this Master Agreement, including without limitation, to the extent applicable, competitive bidding, public notice, election, referendum, prior appropriation or other required procedures has or will be taken and performed as required under the Act and all applicable laws, ordinances, or other applicable regulations, (ii) all persons making up the governing body of Party B are the duly elected or appointed incumbents in their positions and hold such positions in good standing in accordance with the Act and other applicable laws, (iii) entry into and performance of this Master Agreement by Party B are for a proper public purpose within the meaning of the Act and all other relevant constitutional, organic or other governing documents and applicable law, (iv) the term of this Master Agreement does not extend beyond any applicable limitation imposed by the Act or other relevant constitutional, organic or other governing documents and applicable law, (v) Party B’s obligations to make payments with respect to this Master Agreement and each Transaction are to be made solely from the Special Fund, and (vi) obligations to make payments hereunder do not constitute any kind of indebtedness of Party B or create any kind of lien on, or security interest in, any property or revenues of Party B.

D. The Parties agree to add the following sections to Article Three:

Section 3.4 Party B ’s Deliveries . On the Effective Date and as a condition to the obligations of Party A under this Agreement, Party B shall provide Party A (i) certified copies of all ordinances, resolutions, public notices and other documents evidencing the necessary authorizations with respect to the execution, delivery and performance by Party B of this Master Agreement and (ii) a certificate, signed by an officer of Party B and in form and substance reasonably satisfactory to Party A, certifying as to certain factual matters.

Section 3.5 No Immunity Claim. Party B warrants and covenants that with respect to its contractual obligations hereunder and performance thereof, it will not claim immunity on the grounds of sovereignty or similar grounds with respect to the Secured Account from (a) suit, (b) jurisdiction of court (provided that such court is located within a venue

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permitted under the Agreement), (c) relief by way of injunction, order for specific performance or recovery of property, (d) attachment of assets, or (e) execution or enforcement of any judgment; provided, however, that nothing in this Agreement shall waive the obligations and/or rights set forth in the California Government Claims Act (Government Code Section 810 et seq.).

E. If the appropriate box is checked on the Cover Sheet, as an alternative to selecting one of the options under Section 8.3, the Parties agree to add the following section to Article Three:

Section 3.6 Party B Security. With respect to each Transaction, Party B shall have created and set aside a Special Fund and shall have entered into the Security Documents in form and substance reasonably satisfactory to Party A. The Parties agree that Party B’s obligations to make payments with respect to this Master Agreement and each Transaction are to be made solely from the Special Fund.

F. If the appropriate box is checked on the Cover Sheet, the Parties agree to add the following section to Article Eight:

Section 8.4 Party B Security. As credit protection to Party A, and as a condition to the effectiveness of the Confirmation, Party A and Party B shall have entered into the Security Documents, each in form and substance reasonably satisfactory to Party A, and such Security Documents shall have been duly executed and delivered by the Parties and by all third party signatories as contemplated therein and shall be in full force and effect. Party A shall have the rights and remedies specified in the Security Documents and Party B shall comply with its duties, obligations and responsibilities as specified therein. If Party A and Party B still have active or unsettled transactions, then Party B agrees that it shall provide five (5) Business Days prior written notice to Party A before terminating the Secured Account at Depositary Bank and such notice shall include information regarding the replacement Secured Account.

G. The Parties agree to add the following sentence at the end of Section 10.6 - Governing Law:

NOTWITHSTANDING THE FOREGOING, IN RESPECT OF THE

APPLICABILITY OF THE ACT AS HEREIN PROVIDED, THE LAWS
OF THE STATE OF CALIFORNIA SHALL APPLY.

SCHEDULE P: PRODUCTS AND RELATED DEFINITIONS

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“Ancillary Services” means any of the services identified by a Transmission Provider in its transmission tariff as “ancillary services” including, but not limited to, regulation and frequency response, energy imbalance, operating reserve-spinning and operating reserve-supplemental, as may be specified in the Transaction.
“Capacity” has the meaning specified in the Transaction. “Energy” means three-phase, 60-cycle alternating current electric energy, expressed in megawatt hours.
“Firm (LD)” means, with respect to a Transaction, that either Party shall be relieved of its obligations to sell and deliver or purchase and receive without liability only to the extent that, and for the period during which, such performance is prevented by Force Majeure. In the absence of Force Majeure, the Party to which performance is owed shall be entitled to receive from the Party which failed to deliver/receive an amount determined pursuant to Article Four. “Firm Transmission Contingent - Contract Path” means, with respect to a Transaction, that the performance of either Seller or Buyer (as specified in the Transaction) shall be excused, and no damages shall be payable including any amounts determined pursuant to Article Four, if the transmission for such Transaction is interrupted or curtailed and (i) such Party has provided for firm transmission with the transmission provider(s) for the Product in the case of the Seller from the generation source to the Delivery Point or in the case of the Buyer from the Delivery Point to the ultimate sink, and (ii) such interruption or curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the applicable transmission provider’s tariff. This contingency shall excuse performance for the duration of the interruption or curtailment notwithstanding the provisions of the definition of “Force Majeure” in Section 1.23 to the contrary.
“Firm Transmission Contingent - Delivery Point” means, with respect to a Transaction, that the performance of either Seller or Buyer (as specified in the Transaction) shall be excused, and no damages shall be payable including any amounts determined pursuant to Article Four, if the transmission to the Delivery Point (in the case of Seller) or from the Delivery Point (in the case of Buyer) for such Transaction is interrupted or curtailed and (i) such Party has provided for firm transmission with the transmission provider(s) for the Product, in the case of the Seller, to be delivered to the Delivery Point or, in the case of Buyer, to be received at the Delivery Point and (ii) such interruption or curtailment is due to “force majeure” or “uncontrollable force” or a similar term as defined under the applicable transmission provider’s tariff. This transmission contingency excuses performance for the duration of the interruption or curtailment, notwithstanding the provisions of the definition of “Force Majeure” in Section 1.23 to the contrary. Interruptions or curtailments of transmission other than the transmission either immediately to or from the Delivery Point shall not excuse performance.
“Firm (No Force Majeure)” means, with respect to a Transaction, that if either Party fails to perform its obligation to sell and deliver or purchase and receive the Product, the Party to which performance is owed shall be entitled to receive from the Party which failed to perform an amount

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determined pursuant to Article Four. Force Majeure shall not excuse performance of a Firm (No Force Majeure) Transaction.
“Into ______________ (the “Receiving Transmission Provider”), Seller’s Daily Choice” means that, in accordance with the provisions set forth below, (1) the Product shall be scheduled and delivered to an interconnection or interface (“Interface”) either (a) on the Receiving Transmission Provider’s transmission system border or (b) within the control area of the Receiving Transmission Provider if the Product is from a source of generation in that control area, which Interface, in either case, the Receiving Transmission Provider identifies as available for delivery of the Product in or into its control area; and (2) Seller has the right on a daily prescheduled basis to designate the Interface where the Product shall be delivered. An “Into” Product shall be subject to the following provisions:

1. Prescheduling and Notification. Subject to the provisions of Section 6, not later than the prescheduling deadline of 11:00 a.m. CPT on the Business Day before the next delivery day or as otherwise agreed to by Buyer and Seller, Seller shall notify Buyer (“Seller’s Notification”) of Seller’s immediate upstream counterparty and the Interface (the “Designated Interface”) where Seller shall deliver the Product for the next delivery day, and Buyer shall notify Seller of Buyer’s immediate downstream counterparty.

2. Availability of “Firm Transmission” to Buyer at Designated Interface; “Timely Request for Transmission,” “ADI” and “Available Transmission.” In determining availability to Buyer of next-day firm transmission (“Firm Transmission”) from the Designated Interface, a “Timely Request for Transmission” shall mean a properly completed request for Firm Transmission made by Buyer in accordance with the controlling tariff procedures, which request shall be submitted to the Receiving Transmission Provider no later than 30 minutes after delivery of Seller’s Notification, provided, however, if the Receiving Transmission Provider is not accepting requests for Firm Transmission at the time of Seller’s Notification, then such request by Buyer shall be made within 30 minutes of the time when the Receiving Transmission Provider first opens thereafter for purposes of accepting requests for Firm Transmission.

Pursuant to the terms hereof, delivery of the Product may under certain circumstances be redesignated to occur at an Interface other than the Designated Interface (any such alternate designated interface, an “ADI”) either (a) on the Receiving Transmission Provider’s transmission system border or (b) within the control area of the Receiving Transmission Provider if the Product is from a source of generation in that control area, which ADI, in either case, the Receiving Transmission Provider identifies as available for delivery of the Product in or into its control area using either firm or non-firm transmission, as available on a day-ahead or hourly basis (individually or collectively referred to as “Available Transmission”) within the Receiving Transmission Provider’s transmission system.

3. Rights of Buyer and Seller Depending Upon Availability of/Timely Request for Firm Transmission.

A. Timely Request for Firm Transmission made by Buyer, Accepted by the Receiving Transmission Provider and Purchased by Buyer. If a Timely Request for Firm

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Transmission is made by Buyer and is accepted by the Receiving Transmission Provider and Buyer purchases such Firm Transmission, then Seller shall deliver and Buyer shall receive the Product at the Designated Interface.
i. If the Firm Transmission purchased by Buyer within the Receiving Transmission Provider’s transmission system from the Designated Interface ceases to be available to Buyer for any reason, or if Seller is unable to deliver the Product at the Designated Interface for any reason except Buyer’s non-performance, then at Seller’s choice from among the following, Seller shall: (a) to the extent Firm Transmission is available to Buyer from an ADI on a day-ahead basis, require Buyer to purchase such Firm Transmission from such ADI, and schedule and deliver the affected portion of the Product to such ADI on the basis of Buyer’s purchase of Firm Transmission, or (b) require Buyer to purchase non-firm transmission, and schedule and deliver the affected portion of the Product on the basis of Buyer’s purchase of non-firm transmission from the Designated Interface or an ADI designated by Seller, or (c) to the extent firm transmission is available on an hourly basis, require Buyer to purchase firm transmission, and schedule and deliver the affected portion of the Product on the basis of Buyer’s purchase of such hourly firm transmission from the Designated Interface or an ADI designated by Seller.
ii. If the Available Transmission utilized by Buyer as required by Seller pursuant to Section 3A(i) ceases to be available to Buyer for any reason, then Seller shall again have those alternatives stated in Section 3A(i) in order to satisfy its obligations.
iii. Seller’s obligation to schedule and deliver the Product at an ADI is subject to Buyer’s obligation referenced in Section 4B to cooperate reasonably therewith. If Buyer and Seller cannot complete the scheduling and/or delivery at an ADI, then Buyer shall be deemed to have satisfied its receipt obligations to Seller and Seller shall be deemed to have failed its delivery obligations to Buyer, and Seller shall be liable to Buyer for amounts determined pursuant to Article Four.
iv. In each instance in which Buyer and Seller must make alternative scheduling arrangements for delivery at the Designated Interface or an ADI pursuant to Sections 3A(i) or (ii), and Firm Transmission had been purchased by both Seller and Buyer into and within the Receiving Transmission Provider’s transmission system as to the scheduled delivery which could not be completed as a result of the interruption or curtailment of such Firm Transmission, Buyer and Seller shall bear their respective transmission expenses and/or associated congestion charges incurred in connection with efforts to complete delivery by such alternative scheduling and delivery arrangements. In any instance except as set forth in the immediately preceding sentence, Buyer and Seller must make alternative scheduling arrangements for delivery at the Designated Interface or an ADI under Sections 3A(i) or (ii), Seller shall be responsible for any additional

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transmission purchases and/or associated congestion charges incurred by Buyer in connection with such alternative scheduling arrangements.

B. Timely Request for Firm Transmission Made by Buyer but Rejected by the Receiving Transmission Provider. If Buyer’s Timely Request for Firm Transmission is rejected by the Receiving Transmission Provider because of unavailability of Firm Transmission from the Designated Interface, then Buyer shall notify Seller within 15 minutes after receipt of the Receiving Transmission Provider’s notice of rejection (“Buyer’s Rejection Notice”). If Buyer timely notifies Seller of such unavailability of Firm Transmission from the Designated Interface, then Seller shall be obligated either (1) to the extent Firm Transmission is available to Buyer from an ADI on a day-ahead basis, to require Buyer to purchase (at Buyer’s own expense) such Firm Transmission from such ADI and schedule and deliver the Product to such ADI on the basis of Buyer’s purchase of Firm Transmission, and thereafter the provisions in Section 3A shall apply, or (2) to require Buyer to purchase (at Buyer’s own expense) non-firm transmission, and schedule and deliver the Product on the basis of Buyer’s purchase of non-firm transmission from the Designated Interface or an ADI designated by the Seller, in which case Seller shall bear the risk of interruption or curtailment of the non-firm transmission; provided, however, that if the non-firm transmission is interrupted or curtailed or if Seller is unable to deliver the Product for any reason, Seller shall have the right to schedule and deliver the Product to another ADI in order to satisfy its delivery obligations, in which case Seller shall be responsible for any additional transmission purchases and/or associated congestion charges incurred by Buyer in connection with Seller’s inability to deliver the Product as originally prescheduled. If Buyer fails to timely notify Seller of the unavailability of Firm Transmission, then Buyer shall bear the risk of interruption or curtailment of transmission from the Designated Interface, and the provisions of Section 3D shall apply.

C. Timely Request for Firm Transmission Made by Buyer, Accepted by the Receiving Transmission Provider and not Purchased by Buyer. If Buyer’s Timely Request for Firm Transmission is accepted by the Receiving Transmission Provider but Buyer elects to purchase non-firm transmission rather than Firm Transmission to take delivery of the Product, then Buyer shall bear the risk of interruption or curtailment of transmission from the Designated Interface. In such circumstances, if Seller’s delivery is interrupted as a result of transmission relied upon by Buyer from the Designated Interface, then Seller shall be deemed to have satisfied its delivery obligations to Buyer, Buyer shall be deemed to have failed to receive the Product and Buyer shall be liable to Seller for amounts determined pursuant to Article Four.

D. No Timely Request for Firm Transmission Made by Buyer, or Buyer Fails to Timely Send Buyer’s Rejection Notice. If Buyer fails to make a Timely Request for Firm Transmission or Buyer fails to timely deliver Buyer’s Rejection Notice, then Buyer shall bear the risk of interruption or curtailment of transmission from the Designated Interface. In such circumstances, if Seller’s delivery is interrupted as a result of transmission relied upon by Buyer from the Designated Interface, then Seller shall be deemed to have satisfied its delivery obligations to Buyer, Buyer shall be deemed to have

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failed to receive the Product and Buyer shall be liable to Seller for amounts determined pursuant to Article Four.

4. Transmission.

A. Seller’s Responsibilities. Seller shall be responsible for transmission required to deliver the Product to the Designated Interface or ADI, as the case may be. It is expressly agreed that Seller is not required to utilize Firm Transmission for its delivery obligations hereunder, and Seller shall bear the risk of utilizing non-firm transmission. If Seller’s scheduled delivery to Buyer is interrupted as a result of Buyer’s attempted transmission of the Product beyond the Receiving Transmission Provider’s system border, then Seller will be deemed to have satisfied its delivery obligations to Buyer, Buyer shall be deemed to have failed to receive the Product and Buyer shall be liable to Seller for damages pursuant to Article Four.

B. Buyer’s Responsibilities. Buyer shall be responsible for transmission required to receive and transmit the Product at and from the Designated Interface or ADI, as the case may be, and except as specifically provided in Section 3A and 3B, shall be responsible for any costs associated with transmission therefrom. If Seller is attempting to complete the designation of an ADI as a result of Seller’s rights and obligations hereunder, Buyer shall co-operate reasonably with Seller in order to effect such alternate designation.

5. Force Majeure. An “Into” Product shall be subject to the “Force Majeure” provisions in Section 1.23.

6. Multiple Parties in Delivery Chain Involving a Designated Interface. Seller and Buyer recognize that there may be multiple parties involved in the delivery and receipt of the Product at the Designated Interface or ADI to the extent that (1) Seller may be purchasing the Product from a succession of other sellers (“Other Sellers”), the first of which Other Sellers shall be causing the Product to be generated from a source (“Source Seller”) and/or (2) Buyer may be selling the Product to a succession of other buyers (“Other Buyers”), the last of which Other Buyers shall be using the Product to serve its energy needs (“Sink Buyer”). Seller and Buyer further recognize that in certain Transactions neither Seller nor Buyer may originate the decision as to either (a) the original identification of the Designated Interface or ADI (which designation may be made by the Source Seller) or (b) the Timely Request for Firm Transmission or the purchase of other Available Transmission (which request may be made by the Sink Buyer). Accordingly, Seller and Buyer agree as follows:

A. If Seller is not the Source Seller, then Seller shall notify Buyer of the Designated Interface promptly after Seller is notified thereof by the Other Seller with whom Seller has a contractual relationship, but in no event may such designation of the Designated Interface be later than the prescheduling deadline pertaining to the Transaction between Buyer and Seller pursuant to Section 1.

B. If Buyer is not the Sink Buyer, then Buyer shall notify the Other Buyer with whom Buyer has a contractual relationship of the Designated Interface promptly after

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Seller notifies Buyer thereof, with the intent being that the party bearing actual responsibility to secure transmission shall have up to 30 minutes after receipt of the Designated Interface to submit its Timely Request for Firm Transmission.

C. Seller and Buyer each agree that any other communications or actions required to be given or made in connection with this “Into Product” (including without limitation, information relating to an ADI) shall be made or taken promptly after receipt of the relevant information from the Other Sellers and Other Buyers, as the case may be.

D. Seller and Buyer each agree that in certain Transactions time is of the essence and it may be desirable to provide necessary information to Other Sellers and Other Buyers in order to complete the scheduling and delivery of the Product. Accordingly, Seller and Buyer agree that each has the right, but not the obligation, to provide information at its own risk to Other Sellers and Other Buyers, as the case may be, in order to effect the prescheduling, scheduling and delivery of the Product.
“Native Load” means the demand imposed on an electric utility or an entity by the requirements of retail customers located within a franchised service territory that the electric utility or entity has statutory obligation to serve.
“Non-Firm” means, with respect to a Transaction, that delivery or receipt of the Product may be interrupted for any reason or for no reason, without liability on the part of either Party. “System Firm” means that the Product will be supplied from the owned or controlled generation or pre-existing purchased power assets of the system specified in the Transaction (the “System”) with non-firm transmission to and from the Delivery Point, unless a different Transmission Contingency is specified in a Transaction. Seller’s failure to deliver shall be excused: (i) by an event or circumstance which prevents Seller from performing its obligations, which event or circumstance was not anticipated as of the date the Transaction was agreed to, which is not within the reasonable control of, or the result of the negligence of, the Seller; (ii) by Buyer’s failure to perform; (iii) to the extent necessary to preserve the integrity of, or prevent or limit any instability on, the System; (iv) to the extent the System or the control area or reliability council within which the System operates declares an emergency condition, as determined in the system’s, or the control area’s, or reliability council’s reasonable judgment; or (v) by the interruption or curtailment of transmission to the Delivery Point or by the occurrence of any Transmission Contingency specified in a Transaction as excusing Seller’s performance. Buyer’s failure to receive shall be excused (i) by Force Majeure; (ii) by Seller’s failure to perform, or (iii) by the interruption or curtailment of transmission from the Delivery Point or by the occurrence of any Transmission Contingency specified in a Transaction as excusing Buyer’s performance. In any of such events, neither party shall be liable to the other for any damages, including any amounts determined pursuant to Article Four.
“Transmission Contingent” means, with respect to a Transaction, that the performance of either Seller or Buyer (as specified in the Transaction) shall be excused, and no damages shall be payable including any amounts determined pursuant to Article Four, if the transmission for such Transaction is unavailable or interrupted or curtailed for any reason, at any time, anywhere from

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the Seller’s proposed generating source to the Buyer’s proposed ultimate sink, regardless of whether transmission, if any, that such Party is attempting to secure and/or has purchased for the Product is firm or non-firm. If the transmission (whether firm or non-firm) that Seller or Buyer is attempting to secure is from source to sink is unavailable, this contingency excuses performance for the entire Transaction. If the transmission (whether firm or non-firm) that Seller or Buyer has secured from source to sink is interrupted or curtailed for any reason, this contingency excuses performance for the duration of the interruption or curtailment notwithstanding the provisions of the definition of “Force Majeure” in Article 1.23 to the contrary. “Unit Firm” means, with respect to a Transaction, that the Product subject to the Transaction is intended to be supplied from a generation asset or assets specified in the Transaction. Seller’s failure to deliver under a “Unit Firm” Transaction shall be excused: (i) if the specified generation asset(s) are unavailable as a result of a Forced Outage (as defined in the NERC Generating Unit Availability Data System (GADS) Forced Outage reporting guidelines) or (ii) by an event or circumstance that affects the specified generation asset(s) so as to prevent Seller from performing its obligations, which event or circumstance was not anticipated as of the date the Transaction was agreed to, and which is not within the reasonable control of, or the result of the negligence of, the Seller or (iii) by Buyer’s failure to perform. In any of such events, Seller shall not be liable to Buyer for any damages, including any amounts determined pursuant to Article Four.

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EXHIBIT A

MASTER POWER PURCHASE AND SALE AGREEMENT

CONFIRMATION LETTER
This confirmation letter shall confirm the Transaction agreed to on ___________, ___ between __________________________ (“Party A”) and _____________________ (“Party B”) regarding the sale/purchase of the Product under the terms and conditions as follows:

Seller:

Buyer:

Product:
[] Into _________________, Seller’s Daily Choice
[] Firm (LD)
[] Firm (No Force Majeure)
[] System Firm
(Specify System: )
[] Unit Firm
(Specify Unit(s): )
[] Other
[] Transmission Contingency (If not marked, no transmission contingency) [] FT-Contract Path Contingency [] Seller [] Buyer
[] FT-Delivery Point Contingency [] Seller [] Buyer
[] Transmission Contingent [] Seller [] Buyer
[] Other transmission contingency
(Specify: )
Contract Quantity:

Delivery Point:

Contract Price:

Energy Price:

Other Charges:

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Confirmation Letter

Delivery Period:

Special Conditions:

Scheduling:

Option Buyer:

Option Seller:

Type of Option:

Strike Price:

Premium:

Exercise Period:

This confirmation letter is being provided pursuant to and in accordance with the Master Power Purchase and Sale Agreement dated ______________ (the “Master Agreement”) between Party A and Party B, and constitutes part of and is subject to the terms and provisions of such Master Agreement. Terms used but not defined herein shall have the meanings ascribed to them in the Master Agreement. [Party A] [Party B]
Name: Name:

Title: Title:

Phone No: Phone No:

Fax: Fax:

Staff Report Item 6
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Byron Vosburg, Chief Operating Officer
SUBJECT: Adopt Resolution No. OB-2025-04 approving 3CE join Special District Risk Management Authority (“SDRMA”) Joint Powers Authority (“JPA”) and authorize the CEO to execute the SDRMA Memorandum of Understanding (“MOU”) and Program Participation Agreement for the Purpose of Participation in SDRMA Employee Benefits Program
DATE: November 12, 2025
RECOMMENDATION:

This recommends the Operations Board adopt Resolution No. OB-2025-04 approving 3CE join Special District Risk Management Authority (“SDRMA”) Joint Powers Authority (“JPA”) and authorize the CEO to execute the SDRMA Memorandum of Understanding (“MOU”) and Program Participation Agreement for the purpose of participation in SDRMA employee benefits program.

BACKGROUND:

Since 2021 and through 2025, 3CE’s medical benefit plans (health, dental, vision, life, and disability) have been provided through agreement with Fire Risk Management Services (“FRMS”), a JPA established to pool risk among California fire districts and other public agencies.

Unfortunately, on September 23, 2025, FRMS notified 3CE and its other members that it would discontinue offering primary healthcare benefits in 2026 for all members. FRMS would, however, continue to offer ancillary benefits (dental, vision, life, and disability) to interested agencies. For ease of enrollment and consistency for staff, 3CE will continue to work with FRMS for ancillary benefits in 2026.

Staff worked through three separate brokers and to identify, evaluate, and secure primary healthcare coverage for 3CE employees in 2026.

DISCUSSION/ANALYSIS:

Staff prioritized securing cost effective primary medical benefits with our existing network providers and ensuring a consistent enrollment process for 3CE employees.

Staff sourced and reviewed a range of program structures, from pooled medical programs like California Schools Voluntary Employees Benefits Associated (“VEBA”), Municipalities Colleges Schools Insurance Group (“MCSIG”), SDRMA, and Covered California to direct carrier and small group offerings available via selected brokers that included Blue Shield PPOs and Kaiser HMOs.

Staff determined SDRMA to be the option to best serve 3CE employee needs due to the similarity of its Blue Shield PPO and Kaiser HMO benefit offerings to the 2025 benefits offered to employees via FRMS with the lowest likelihood of requiring any switch in provider.

SRDMA’s premiums were in the middle of the range of available options. SDRMA’s coverage plan includes significantly lower out-of-pocket maximums for employees, administrative support, and customer service offered via SDRMA that a small-group provider is unlikely to match.

Formed in 1986, SDRMA is a JPA established to provide local government agencies with insurance coverage, originally to include workers’ compensation, general liability, and similar organizational insurance and risk management products. In 2006, SDRMA expanded to include a small group health benefits program via Public Risk Innovation, Solutions, and Management (PRISM) to offer its members competitive primary and ancillary medical insurance coverage.

If approved, the new medical program will be effective January 1, 2026. The new SDRMA medical program is expected to offer 3CE employees three primary medical plan options, two Blue Sheild PPOs and one Kaiser HMO, which will complement the ancillary offerings continued via FRMS. 3CE’s participation has already been approved by SDRMA’s underwriters.

FISCAL IMPACT:

Healthcare costs have increased significantly in the last year, but the precise financial impact is not known at this time. Final 3CE costs will depend upon employee participation and coverage plan elections and are expected to be within the currently budgeted $1.1 million.

CONCLUSION:

This recommends the Operations Board adopt Resolution No. OB-2025-04 to join Special District Risk Management Authority (“SDRMA”) Joint Powers Authority (“JPA”) and authorize the CEO to execute the SDRMA Memorandum of Understanding (“MOU”) and Program Participation Agreement for the purpose of participation in SDRMA employee benefits program to ensure that 3CE employees receive continuous, consistent healthcare coverage into 2026.

ATTACHMENT(S):

1. DRAFT Resolution No. OB-2025-04

2. DRAFT Memorandum of Understanding by and between SDRMA and 3CE

3. SDRMA Program Participation Agreement

RESOLUTION NO. OB-2025-04

A RESOLUTION OF THE OPERATIONS BOARD OF DIRECTORS OF CENTRAL COAST COMMUNITY

ENERGY APPROVING THE FORM OF AND AUTHORIZING THE

EXECUTION OF A MEMORANDUM OF UNDERSTANDING AND AUTHORIZING PARTICIPATION IN THE SPECIAL DISTRICT RISK MANAGEMENT AUTHORITY’S

HEALTH BENEFITS PROGRAM
WHEREAS, Central Coast Community Energy, a public agency duly organized and existing under and by virtue of the laws of the State of California (the “ENTITY”), has determined that it is in the best interest and to the advantage of the ENTITY to participate in the Health Benefits Program offered by Special District Risk Management Authority (the “Authority”); and WHEREAS, the Authority was formed in 1986 in accordance with the provisions of California Government Code 6500 et seq., for the purpose of providing risk financing, risk management programs and other coverage protection programs; and
WHEREAS, participation in Authority programs requires the ENTITY to execute and enter into a Memorandum of Understanding which states the purpose and participation requirements for the Health Benefits Program; and
WHEREAS, all acts, conditions and things required by the laws of the State of California to exist, to have happened and to have been performed precedent to and in connection with the consummation of the transactions authorized hereby do exist, have happened and have been performed in regular and due time, form and manner as required by law, and the ENTITY is now duly authorized and empowered, pursuant to each and every requirement of law, to consummate such transactions for the purpose, in the manner and upon the terms herein provided.

NOW, THEREFORE, BE IT RESOLVED BY THE GOVERNING BODY OF THE ENTITY AS FOLLOWS:

Section 1. Findings. The ENTITY’s Governing Body hereby specifically finds and determines that the actions authorized hereby relate to the public affairs of the ENTITY.

Section 2. Memorandum of Understanding. The Memorandum of Understanding, to be executed and entered into by and between the ENTITY and the Authority, in the form presented at this meeting and on file with the ENTITY’s Secretary, is hereby approved. The ENTITY’s Governing Body and/or Authorized Officers (“The Authorized Officers”) are hereby authorized and directed, for and in the name and on behalf of the ENTITY, to execute and deliver to the Authority the Memorandum of Understanding.

Section 3. Program Participation. The ENTITY’s Governing Body approves participating in the Special District Risk Management Authority’s Health Benefits Program.

Section 4. Severability. If any provision of this resolution or the application thereof to any person or circumstance is held invalid, such invalidity shall not affect other provisions or applications of the resolution which can be given effect without the invalid provision or application, and to this end the provisions of this resolution are severable.

Section 5. Other Actions. The Authorized Officers of the ENTITY are each hereby authorized and directed to execute and deliver any and all documents which are necessary in order to consummate the transactions authorized hereby and all such actions heretofore taken by such officers are hereby ratified, confirmed and approved.

Section 6. Effective Date. This resolution shall take effect immediately upon its passage.

PASSED AND ADOPTED this _____ day of __________________, 20_____ by the following vote:

AYES:

NOES:

ABSENT:

Chair
Board Clerk

Special District Risk Management Authority Page 1:4 Tel 800.537.7790 Fax 916.231.4111
www.sdrma.org

MEMORANDUM OF UNDERSTANDING
THIS MEMORANDUM OF UNDERSTANDING (HEREAFTER “MEMORANDUM”) IS

ENTERED INTO BY AND BETWEEN THE SPECIAL DISTRICT RISK MANAGEMENT AUTHORITY (HEREAFTER “SDRMA”) AND THE PARTICIPATING PUBLIC ENTITY (HEREAFTER “ENTITY”) WHO IS SIGNATORY TO THIS MEMORANDUM.

WHEREAS, on August 1, 2006, SDRMA was appointed administrator for the purpose of enrolling small public entities into the Public Risk Innovation, Solutions and Management (PRISM) Health and/or Employee Benefits Small Group Program (hereinafter "PROGRAM"); and WHEREAS, the terms and conditions of the PROGRAM as well as benefit coverage, rates, assessments, and premiums are governed by the PRISM Health Committee and/or PRISM Employee Benefits Committee for the PROGRAM (the "COMMITTEE") and not SDRMA; and WHEREAS, ENTITY desires to enroll and participate in the PROGRAM.

NOW THEREFORE, SDRMA and ENTITY agree as follows:

1. PURPOSE. ENTITY is signatory to this MEMORANDUM for the express purpose of enrolling in the PROGRAM.

2. ENTRY INTO PROGRAM. ENTITY shall enroll in the PROGRAM by making application through SDRMA which shall be subject to approval by the PROGRAM's Underwriter and governing documents and in accordance with applicable eligibility guidelines.

3. MAINTENANCE OF EFFORT. PROGRAM is designed to provide an alternative health benefit solution to all participants of the ENTITY including active employees, retired employees (optional), dependents (optional) and public officials (optional). ENTITY public officials may participate in the PROGRAM only if they are currently being covered and their own ENTITY’s enabling act, plans and policies allow it. ENTITY must contribute at least the minimum percentage required by the eligibility requirements

4. PREMIUMS. ENTITY understands that premiums and rates for the PROGRAM are set by the COMMITTEE. ENTITY will remit monthly premiums based upon rates established for each category of participants and the census of covered employees, public officials, dependents and retirees.

Rates for the ENTITY and each category of participant will be determined by the COMMITTEE designated for the PROGRAM based upon advice from its consultants and/or a consulting Benefits Actuary and insurance carriers. In addition, SDRMA adds an administrative fee to premiums and rates for costs associated with administering the PROGRAM. Rates may vary depending upon factors including, but not limited to,

Special District Risk Management Authority Page 2:4 Tel 800.537.7790 Fax 916.231.4111
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demographic characteristics, loss experience of all public entities participating in the PROGRAM and differences in benefits provided (plan design), if any.

SDRMA will administrate a billing to ENTITY each month, with payments due by the date specified by SDRMA. Payments received after the specified date will accrue penalties up to and including termination from the PROGRAM. Premiums are based on a full month, and there are no partial months or prorated premiums. Enrollment for mid-year qualifying events and termination of coverage will be made in accordance with the SDRMA Program Administrative Guidelines.

5. BENEFITS. Benefits provided to ENTITY participants shall be as set forth in ENTITY’s Plan Summary for the PROGRAM and as agreed upon between the ENTITY and its recognized employee organizations as applicable. Not all plan offerings will be available to ENTITY, and plans requested by ENTITY must be submitted to PROGRAM underwriter for approval.

6. COVERAGE DOCUMENTS. Except as otherwise provided herein, coverage documents from each carrier outlining the coverage provided, including terms and conditions of coverage, are controlling with respect to the coverage of the PROGRAM and will be provided by SDRMA to each ENTITY. SDRMA will provide each ENTITY with additional documentation, defined as the SDRMA Program Administrative Guidelines which provide further details on administration of the PROGRAM.

7. PROGRAM FUNDING. It is the intent of this MEMORANDUM to provide for a fully funded PROGRAM by any or all of the following: pooling risk; purchasing individual stop loss coverage to protect the pool from large claims; and purchasing aggregate stop loss coverage.

8. ASSESSMENTS. Should the PROGRAM not be adequately funded for any reason, pro-rata assessments to the ENTITY may be utilized to ensure the approved funding level for applicable policy periods. Any assessments which are deemed necessary to ensure approved funding levels shall be made upon the determination and approval of the COMMITTEE in accordance with the following:
a. Assessments/dividends will be used sparingly. Generally, any over/under funding will be factored into renewal rates.
b. If a dividend/assessment is declared, allocation will be based upon each ENTITY’S proportional share of total premiums paid for the preceding 3 years. An ENTITY must be a current participant to receive a dividend, except upon termination of the PROGRAM and distribution of assets.

Special District Risk Management Authority Page 3:4 Tel 800.537.7790 Fax 916.231.4111
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c. ENTITY will be liable for assessments for 12 months following withdrawal from the PROGRAM.
d. Fund equity will be evaluated on a total PROGRAM-wide basis as opposed to each year standing on its own.

9. WITHDRAWAL. ENTITY may withdraw subject to the following condition: ENTITY shall notify SDRMA and the PROGRAM in writing of its intent to withdraw at least 90 days prior to their requested withdrawal date. ENTITY may rescind its notice of intent to withdraw. Once ENTITY withdraws from the PROGRAM, there is a 3-year waiting period to come back into the PROGRAM, and the ENTITY will be subject to underwriting approval again.

10. LIAISON WITH SDRMA. Each ENTITY shall maintain staff to act as liaison with SDRMA and between the ENTITY and SDRMA’S designated PROGRAM representative.

11. GOVERNING LAW. This MEMORANDUM shall be governed in accordance with the laws of the State of California.

12. VENUE. Venue for any dispute or enforcement shall be in Sacramento, California.

13. ATTORNEY FEES. The prevailing party in any dispute shall be entitled to an award of reasonable attorney fees.

14. COMPLETE AGREEMENT. This MEMORANDUM together with the related PROGRAM documents constitutes the full and complete agreement of the ENTITY.

15. SEVERABILITY. Should any provision of this MEMORANDUM be judicially determined to be void or unenforceable, such determination shall not affect any remaining provision.

16. AMENDMENT OF MEMORANDUM. This MEMORANDUM may be amended by the SDRMA Board of Directors and such amendments are subject to approval of ENTITY’S designated representative, or alternate, who shall have authority to execute this MEMORANDUM.

Any ENTITY who fails or refuses to execute an amendment to this MEMORANDUM shall be deemed to have withdrawn from the PROGRAM on the next annual renewal date.

17. EFFECTIVE DATE. This MEMORANDUM shall become effective on the later of the first date of coverage for the ENTITY or the date of signing of this MEMORANDUM by the Chief Executive Officer or Board President of SDRMA.

18. EXECUTION IN COUNTERPARTS. This MEMORANDUM may be executed in several counterparts, each of which shall be an original, all of which shall constitute but one and the same instrument.

Special District Risk Management Authority Page 4:4 Tel 800.537.7790 Fax 916.231.4111
www.sdrma.org
In Witness Whereof, the undersigned have executed the MEMORANDUM as of the date set forth below.

Dated: By:

Special District Risk
Management Authority
Dated: By:

Central Coast Community Energy

1 To: Central Coast Community Energy Effective
From: PRISM / AUS Underwriting
Date: November 3, 2025
Re: Central Coast Community Energy Effective: Small Group Program Application Approval
We are happy to approve the application of Central Coast Community Energy Effective for acceptance to participate in the PRISM Small Group program.

As part of this acceptance, you will find two attachments to this letter:

1. Program Underwriting & Eligibility Rules

2. Program Participation Agreement
The Underwriting and Eligibility Rules are designed to serve as a guide for program rules and expectations. These rules outline expectations of member conduct within the program and have been established to protect both the pool and the member from actions that may increase the cost and/or risk in the program.

The Program Participation Agreement details the final terms of acceptance and any special exceptions or terms that have been made as part of this approval. Please read these terms carefully and contact your representative at SDRMA if you have any questions or require clarification(s).

Central Coast Community Energy Effective’s completion and execution of the Program Participation Agreement will constitute full acceptance of the organization as a member of the PRISM Small Group program and deem it eligible to participate in the insurance coverage plan(s) applied for and approved in this agreement. Please return the signed Program Participation Agreement to SDRMA.

We thank you for your interest in the PRISM Small Group program and look forward to your participation in the program.

Sincerely,
Annalyse Clapp

FOR INTERNAL USE ONLY
Application is: X Accepted Rejected Case No.

Effective: January 1, 2026 Underwriter: Annalyse Clapp
Date: 11/3/2025 By:
(Signature)

2 Health Program Eligibility Guidelines
Active Full-Time Employees Full-time salaried or hourly employees who are actively at work at least 30 hours per week.

Active Part-Time Employees Part-time employees who are actively at work at least 20 hours per week.

Dependent Eligibility
Eligible dependents are covered to age 26 and will terminate coverage first of the month following 26th Birthday. Disabled dependents are covered regardless of age but must be approved by the plan administrator (claim fiduciary medical management) prior to annual enrollment.

COBRA Participants Eligible to elect coverage through COBRA.

Board members, Trustees,
Council Members, or Other
Elected officials
Directors, board members, and other elected/appointed officials can only elect plan if they are eligible on the current plan and are subject to the same requirements as Active employees. Exceptions can be made at the recommendation of AUS and with the approval of the PRISMHealth Committee.

Retirees
To qualify for Medicare plans and rates, retiree must be enrolled in Medicare Parts A&B at their own cost.

Retired employees who are currently eligible and participating on the plan will be eligible to continue coverage under the program, if the coverage permits. Retirees who declined coverage may not enroll in any coverage at a subsequent enrollment date. Exceptions can be made at the recommendation of AUS.

Medicare Eligible retirees must enroll in Medicare parts A&B Health Program Underwriting Guidelines (Continued on next page) Group Size Requirements
Minimum/Maximum including
Full-Time Eligible Employees, Part-Time
Eligible Employees, Non-Medicare Retirees,
Medicare Retirees, Board Members, Trustees,
Council Members, or Other Elected Officials
Minimum: 2
Maximum: 200
Participation Guidelines
Active Employees, Non-Medicare Retirees,
Medicare Retirees, Board Members, Trustees,
Council Members, or Other Elected Officials
• Minimum participation of 75% of all eligible population. • Non-Medicare Retirees will be thoroughly reviewed by
AUS if they exceed 20% of the total covered population
• Exceptions can be made at the recommendation of AUS
and with the approval of the PRISMHealth Committee
Employer Contributions
Contributions should be structured to allocate cost for tiers with dependent coverage. Cash-Back or "Cash-in-lieu-of" employer contributions are not preferred unless a specific exception has been made by underwriting.

Gap Funding: Gap funding is an account established to run alongside a health plan that supplements out-of-pocket medical expenses incurred through the plan and that would normally be paid by the covered individual. PRISM offers High Deductible Health Plan (HDHP) options that are underwritten to include the

SMALL GROUP PROGRAM UNDERWRITING & ELIGIBILITY GUIDELINES (Subject to attached Custom Contingencies and Caveats section)

3 use of Health Savings Accounts (HSAs) for gap funding purposes. The program offered HDHPs are not eligible to run alongside Health Reimbursement Arrangements (HRAs) or any other type of external gap funding plan or mechanism. All other medical plans offered within the PRISMHealth portfolio (HMO, Silver PPO, Gold PPO, EPO, etc.) are not considered eligible for gap funding of any type.

Active Employees, Part-Time Eligible
Employees, Board Members, Trustees, Council
Members, or Other Elected Officials
Employer pays Minimum 75% of the single-only cost, 50%
suggested contribution for dependents.

Retirees No minimum employer contribution.

Waiting Period
Date of hire is not allowed unless hire date is on the first of the month. All plan changes resulting from Qualifying Events will be effective on the 1st of the month following the event. Births and deaths are exceptions where coverage will be added/dropped on the event date rather than the first of the month following. If dependents are covered when a retiree or employee passes away, dependent coverage will continue to the end of the month.

Waivers
Coverage can only be waived with proof of group coverage through spouse, other group coverage, Medicare/Medi-Cal/Medicaid or COBRA. Waivers will be reviewed by AUS if they exceed 25% of the total covered population. Exceptions can be made at the recommendation of underwriting and with the approval of the PRISMHealth Committee or PRISM staff. Non-Program participants are excluded from this waiver definition (i.e. union carve-out, PORAC).

Lock-out period
Small group members will comply with the withdrawal and termination rules of the JPA in which they contract for coverage.

Plan Selections and Combinations Guidelines
Plan Selections
Subject to underwriting review and approval:
• 2-100 enrolled lives: 2 non-Kaiser plans + 1 Kaiser plan • 101-200 enrolled lives: 3 non-Kaiser plans + 1 Kaiser plan Plan Combinations
• Only 1 non-Kaiser HMO or HDHP plan may be offered to an employee group • Groups requesting more than 1 non-Kaiser HMO or more than 1 HDHP require approval from PRISM/AUS underwriting
• Future plan changes are subject to review and approval by PRISM/AUS underwriting
Other Programs
• The PRISMHealth Program should be offered as a full takeover program in most situations.
• The PRISMHealth Program will consider a carve-out option alongside CalPERS exclusively (not dual choice). The current plans and enrollment will be reviewed and approved via the Underwriting process and disclosed to the PRISMHealth Committee.
• Other program carve-outs will not be allowed.

4 Dental, Vision, Life, Disability and EAP Program Eligibility Guidelines The following underwriting guidelines assume the employer will only be offering the PRISM Small Group coverage plans to an employee group.

Active Full-Time Employees Full-time salaried or hourly employees who are actively at work at least 30 hours per week.

Active Part-Time Employees Part-time employees who are actively at work at least 20 hours per week.

Dependent Eligibility
• Eligible dependents are covered to age 26 and will terminate coverage first of the month following 26th Birthday. Disabled dependents are covered regardless of age but must be approved by the plan administrator (claim fiduciary medical management) prior to annual enrollment.

COBRA Participants
• Dental & Vision: Eligible to elect coverage through COBRA • Life/AD&D, Disability, EAP: Not eligible to elect coverage through COBRA
Board members, Trustees,
Council Members, or Other
Elected officials
• Dental, Vision, Life/AD&D, EAP: Directors, board members, and other elected/appointed officials can only elect plan if they are eligible on the current plan and are subject to the same requirements as Active employees.
• Supplemental Life and Disability: Not eligible
Retirees • Dental and Vision: Eligible
• Life/AD&D, Disability, and EAP: Not eligible
Dental, Vision, Life, Disability and EAP Program Underwriting Guidelines Group Size Requirements
Minimum/Maximum include Full-time
Eligible Employees, Part-Time Eligible
Employees, Non-Medicare Retirees, and
Medicare Retirees, Board Members,
Trustees, Council Members, or Other
Elected officials
Minimum: 2
Maximum: Up to 50*
Participation Guidelines
Active Employees, Retirees and Board
Members, Trustees, Council Members, or
Other Elected officials
 Dental and Vision: 75% of all eligible
 Life/AD&D, Disability, and EAP: 75% of all eligible
(Retirees not eligible)
Employer Contributions
Contributions should be structured to allocate cost for tiers with dependent coverage. Cash-Back or "Cash-in-lieu-of" employer contributions are not permitted unless a specific exception* has been made by underwriting.

Active Employees, Board members,
Trustees, Council Members, or Other
Elected officials
Employer pays 75% of the single-only cost, except for
Supplemental Life. 50% suggested contribution for
dependents.

Retirees No minimum employer contribution (for eligible lines of coverage).

Lock-out period

5 Small group members will comply with the withdrawal and termination rules of the JPA in which they contract for coverage.

Plan Selection Guidelines
Plan Selection
• Dental: Employers can select 1 Dental PPO plan + 1
Dental DHMO
• Vision/EAP: Employers can select one plan to offer
their employees and dependents
• Basic Life and AD&D: Employer can select a plan for
each class of employee (Designated by level of
benefit)
* At the discretion of Underwriting. See Special Acceptance Terms section of Program Participation Agreement for further detail.

6 The coverage and premiums offered under this agreement are based on the information provided. The submission of any false information may result in the denial of coverage. The provision of known false or misleading information shall render this agreement null and void, and any insurance coverage offered hereunder shall be withdrawn retroactively to the effective date of the policy.

Central Coast Community Energy is approved for the following products:

Health X Dental Vision Life Disability EAP
Future underwriting approval is required for coverage not requested / approved above.

Special Acceptance Terms
• Central Coast Community Energy is eligible to enroll in up to (UW to Select Two or three medical plans+ 1 Kaiser plan) subject to plan combination limitations. (refer to Plan Combination section) • Rate proposal assumes full takeover of existing benefit plans and carriers. • PRISM/AUS Underwriting has approved an exception for this group's cash-in-lieu-of as follows: PRISM proposal assumes cash-in-lieu amount will not increase by more than $812. Proof of other group coverage is required for all employees waiving coverage.

Standard Acceptance Terms
• The Underwriting & Eligibility Rules are part of the terms of this agreement and apply unless stated otherwise in the Special Acceptance Terms.
• Proposed rates are guaranteed ONLY for the current population of Central Coast Community Energy, including all currently covered active employees, retirees and public officials (where approved). • This proposal includes applicable Affordable Care Act Government Fees (Health plans only). • Rate proposal assumes current enrollment as provided in census file submitted in Interest Packet. PRISM reserves the right to potentially non-renew if the following changes occur and no corrective action is taken by the member organization:
o If total program enrollment changes by more than 10%. o If the distribution of Actives versus non-Medicare Retirees changes by more than 10%. o If the tiered enrollment distribution changes by more than 10%. o If employer's contribution towards the employee only cost falls below 75%. This proposal assumes current employer contribution is at least 75% of employee-only cost unless a specific exception has been provided by underwriting. Contribution requirement does not apply to Supplemental Life.

GENERAL AGREEMENT AND SIGNATURE
Effective date requested:_________________________________________ (Actual date will be assigned by PRISM if application is accepted). Application is hereby made to PRISM or the appropriate affiliated company for Employee Benefits coverage identified above. If this application is accepted, this Program Participation Agreement will become part of the agreement to join the program.

Upon Acceptance of the application, Central Coast Community Energy will inform all persons who are eligible for coverage that they may apply for PRISM coverage under the Agreement/Policy. By signing below Central Coast Community Energy acknowledges receipt of and adherence to PRISM’s underwriting and eligibility guidelines and the terms of the Program Participation Agreement.

By:__________________________________________________Title:____________________________ (Authorized Signature)

PROGRAM PARTICIPATION AGREEMENT

7 Printed Name:_________________________________________________________________________

Staff Report Item 7
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Geoffrey Ihle, Director of Energy Risk Management SUBJECT: Adopt Resolution No. OB-2025-05 approving amendments to 3CE’s Energy Risk Management (ERM) Policy as recommended by the Risk Management Committee (RMC)
DATE: November 12, 2025
RECOMMENDATION:

This recommends the Operations Board adopt Resolution No. OB-2025-05 approving amendments to 3CE’s Energy Risk Management (ERM) Policy as recommended by the Risk Management Committee (RMC).

BACKGROUND:

The Energy Risk Management (ERM) Policy establishes 3CE’s risk management functions and procedures to identify, quantify, and manage the risks associated with power procurement activities.

It establishes management responsibilities, organizational structures, risk management standards, and operating controls and limits necessary to properly identify and manage 3CE’s risk to support meeting its energy procurement goals.

The Policy Board first approved the ERM Policy in March 2018. The March 2018 policy set forth that future amendments were to be considered and recommended by the RMC and approved by the Operations Board. The ERM Policy was further revised in September 2018, November 2020. The June 2022 revision permitted the RMC to amend appendixes with subsequent notice to the Operations Board to ensure timely and effective administration of the ERM Policy. The ERM Policy was last amended in October 2024.

DISCUSSION/ANALYSIS:

Regular review of the ERM Policy ensures that it evolves to address potential market, regulatory, or business changes that impact 3CE’s procurement of energy and energy related products. 2025 Policy revisions are clarifications, minor adjustments, or additions.

Clarifications, Minor Hedge Tolerance Adjustments, Additions Clarification

4.6 Authorized Markets, Products: Clarified that counterparty enabling agreements are approved and executed by 3CE’s CEO (or designee). This reflects current practice, removes unnecessary Board items, and does not create financial obligations since enabling agreements only establish the standard contractual framework for future transactions.

Staff will report newly enabled counterparties to the Board at the next available Operations Board as part of the CEO Report.

Clarification

5.1 Hedging Tolerances: Clarified that sales of energy, capacity, renewable attributes, and other market products are permitted when needed to rebalance the portfolio to align with 3CE’s risk tolerances and policy objectives. While 3CE is generally a purchaser, sales may occur to maintain portfolio balance, and such transactions will be conducted in accordance with this Policy and applicable Delegation of Authority.

Hedge Tolerance Adjustments

5.1.1 Energy Procurement: Reduced the hedge compliance horizon from 40 quarters to 16 forward quarters (four years) to align hedge activity with the period in which positions can be efficiently and economically managed using short- to medium-term market transactions.

5.1.2 Renewable Procurement: Replaced the prior minimum/maximum hedge bands with annual minimum hedge requirements for RPS vintages 2025–2027+, aligned the Policy reference from SB 350 to SB 100, and clarified measurement language to reflect long-term renewable procurement practices.

Maximums were removed as they are less meaningful for managing variable-volume renewable PPAs.

Clarified that PCC2 purchases are optional rather than required.

5.1.3 Capacity Procurement: Adjusted the minimum hedge requirement for RA to apply to the shortest hour of each month (rather than every hour) and reduced the compliance horizon from ten years to five years, providing equivalent reliability coverage over the manageable horizon while allowing greater flexibility under evolving regulatory frameworks.

Allowed Product Additions
Appendix A. Authorized Transaction Types, Regions, and Markets: Added physical and financial natural gas products as authorized transaction types to enable fuel cost stabilization and generate more predictable economics for potential battery-natural gas co-located projects.

FISCAL IMPACT:

None.

CONCLUSION:

The Operations Board of Directors adoption of Resolution OB-2025-05 revisions to 3CE’s Energy Risk Management Policy as recommended by the Risk Management Committee at its September 2025 meeting ensures the ERM Policy continues to meet business needs to ensure 3CE’s effective operations while maintaining sufficient risk tolerances.

ATTACHMENT(S):

1. Energy Risk Management Policy redline

2. Energy Risk Management Policy clean

3. Draft Resolution OB-2025-05

1 Energy Risk
Management Policy
(ERMP)
Sixth Revision November 2025 – Operations Board of Directors Approved Fifth Revision October 2024 – Operations Board of Directors Approved Fourth Revision August 2023- Risk Management Committee Approved Third Revision August 2022 – Operations Board of Directors Approved Second Revision November 2020 –Operations Board of Directors Approved First Revision September 2018 –Operations Board of Directors Approved Initial Version March 2018 –Policy Board of Directors Approved

2 Table of Contents
Table of Contents
SECTION 1: ERMP OVERVIEW .......................................................................................................................5

1.1 Background and Purpose ....................................................................................................................5

1.2 Scope...................................................................................................................................................5

1.3 Energy Risk Management Objective ...................................................................................................6

1.4 Policy Administration..........................................................................................................................6 SECTION 2: GOALS AND RISK EXPOSURES ....................................................................................................7

2.1 ERMP Goals.........................................................................................................................................7

2.2 Risk Catalog.........................................................................................................................................7

2.2.1 Customer Opt-Out Risk ................................................................................................................8

2.2.2 Market Risk ..................................................................................................................................8

2.2.3 Liquidity Risk ................................................................................................................................8

2.2.4 Regulatory and Legislative Risk....................................................................................................9

2.2.5 Volumetric Risk ............................................................................................................................9

2.2.6 Model Risk....................................................................................................................................9

2.2.7 Operational Risk.........................................................................................................................10

2.2.8 Counterparty & Generalized Credit Risk....................................................................................10 SECTION 3: ORGANIZATIONAL STRUCTURE AND RESPONSIBILITIES ..........................................................11

3.1 Risk Management Organizational Structure.....................................................................................11

3.2 Risk Management Committee ..........................................................................................................11

3.3 Segregation of Duties........................................................................................................................12

3.3.1 Front Office ................................................................................................................................12

3.3.2 Middle Office..............................................................................................................................13

3.3.3 Back Office .................................................................................................................................14 SECTION 4: BUSINESS PRACTICES ...............................................................................................................15

4.1 General Conduct ...............................................................................................................................15

4.2 Hedging & Trading Activities; Prohibition on Speculation................................................................15

3 4.3 Trading for Personal Accounts..........................................................................................................15

4.4 Conflict of Interest ............................................................................................................................15

4.5 Adherence to Statutory Requirements.............................................................................................16

4.6 Authorized Products, Markets & Terms............................................................................................16

4.7 System of Record ..............................................................................................................................17

4.8 Transaction Valuation .......................................................................................................................17

4.9 Policy Compliance .............................................................................................................................17 SECTION 5: TOLERANCES ............................................................................................................................18

5.1 Hedging Tolerances.........................................................................................................................18

5.1.1 Energy Procurement Tolerances................................................................................................18

5.1.3 Capacity Procurement Tolerances...........................................................................................21

5.1.4 Carbon-Free Energy Tolerances.................................................................................................22

5.1.5 Congestion Revenue Rights (CRRs) ...........................................................................................22

5.2 Monitoring, Reporting and Instances of Exceeding Risk Limits........................................................23 SECTION 6: CREDIT POLICY..........................................................................................................................24 SECTION 7: POSITION TRACKING AND MANAGEMENT REPORTING ..........................................................25 SECTION 8: POLICY REVISION PROCESS ......................................................................................................26

8.1 Acknowledgement of Policy..............................................................................................................26

8.2 Policy Interpretations........................................................................................................................26 SECTION 9: DELEGATION OF FINANCIAL AUTHORITY.................................................................................27 Appendix A: AUTHORIZED TRANSACTION TYPES, REGIONS, AND MARKETS .............................................28 Appendix B: NEW TRANSACTION APPROVAL FORM ..................................................................................29 Appendix C: DEFINITIONS ...........................................................................................................................30

4

5 SECTION 1: ERMP OVERVIEW

1.1 Background and Purpose
Central Coast Community Energy (3CE), formerly Monterey Bay Community Power Authority, is a public Joint Powers Authority (JPA) located within the geographic boundaries of Monterey, Santa Cruz, San Benito, San Luis Obispo and Santa Barbara Counties. Member agencies of 3CE include the Counties of Monterey, San Luis Obispo, Santa Cruz, San Benito, and Santa Barbara, as well as certain incorporated cities located within the member counties1. 3CE members elected to implement and administer a community choice aggregation (“CCA”) program.

The CCA program provides its members an opportunity to procure electricity supplies and implement local programs that meet the goals of the local communities. Electricity procured to serve customers will continue to be delivered over the Investor-Owned Utilities’ (PG&E & SCE) transmission and distribution systems.
3CE exists to serve its local government members, and the residences and businesses located within their respective communities. 3CE’s specific objectives are to lower greenhouse gas (GHG) emissions by reliably supplying its customers with electricity sourced from clean and renewable generation resources at competitive rates along with innovative electrification programs. 3CE also functions to stimulate the local economy and give its member agencies greater choice in the energy procured for their residents.

Providing retail electric generation service to customers enrolled in the CCA program exposes 3CE, and ultimately the customers it serves, to various significant but manageable risks. The intent of this Energy Risk Management Policy (ERMP) is to provide 3CE, and by extension its customers, with a framework to identify, monitor and manage risks associated with procuring power supplies and operating in wholesale energy markets.

This Energy Risk Management Policy, including its appendices, establishes 3CE’s Energy Risk Management Program.

1.2 Scope
Unless otherwise explicitly stated in this ERMP orotherpolicies approved by the appropriate 3CE Board, this ERMP applies to all power procurement and related business activities that may impact the risk profile of 3CE. This ERMP documents the framework by which 3CE staff and consultants will:
 Identify, quantify and manage risk
 Develop and execute procurement strategies

1 Presently, all cities within the five County footprint are 3CE members, with the exception of King City, Lompoc, and the City of Santa Barbara. 3CE will begin serving customers in Atascadero and the unincorporated portions of San Luis Obispo County in January 2025.

6  Develop a framework of controls and oversight
 Monitor, measure, and report on the effectiveness of the ERMP To ensure its successful operation, 3CE may partner with experienced consultants to provide power supply services when appropriate. Specific to power procurement, 3CE has partnered with two third-party Scheduling Coordinatorsthat augment 3CE’s internal Front (scheduling), Middle (monitoring) and Back (settlement) Offices related activities as discussed at Section 3.3. The Scheduling Coordinators, as well as all other consultants supporting 3CE’s power procurement activities, will adhere to and be governed by this ERMP in providing these services to 3CE. In addition, Scheduling Coordinators’ and other consultants’ activities executed on 3CE’s behalf will be governed by their own internal risk management policies and procedures, and prudent industry practices.

1.3 Energy Risk Management Objective
The objective of this ERMP is to provide a framework for conducting procurement activities that will facilitate risk management in an effort to meet 3CE’s goals as listed in Section 2.1.

Pursuant to this ERMP, 3CE will identify and measure the magnitude of the risks to which it is exposed and take the necessary steps to manage and reduce those risks to acceptable levels.

1.4 Policy Administration
This ERMP shall be reviewed and approved at least annually by the 3CE Operations Board of Directors (Board). The Risk Management Committee (RMC) and Operations Board must approve amendments to the ERMP, except for the appendices, which may be amended with approval of only the RMC. The RMC must give timely notice to the Board of any amendment it makes to an appendix or a reference policy or procedure document.

7 SECTION 2: GOALS AND RISK EXPOSURES

2.1 ERMP Goals
3CE operates in dynamic, volatile environments and markets. Prices for energy and its underlying drivers, such as natural gas, are susceptible to unpredictable and sometimes significant changes in short intervals. Regulatory and legislative actions can structurally change markets, market price levels, and procurement requirements. Low liquidity and financial dislocations may lead to counterparty distress. 3CE’s Energy Risk Management Policy (ERMP) is designed to address these challenges. Its overarching goals are the following:
 Preserving the financial health and stability of 3CE
 Providing rate stability
 Ensuring the long-term viability of 3CE
In furtherance of these goals 3CE strives to:
 Maintain a credit rating of A- or equivalent, as defined by S&P Global Ratings or an equivalent ratings agency
 Limit power supply cost variance to the annual budget to 10%, barring extraordinary circumstances
 Fund its Rate Stabilization Fund at levels that buffer customers from rate shock and maintain a competitive market position
The ERMP is a strategic document, not a prescriptive manual. The metrics, limits, and products used to measure and manage risk must continuously evolve to reflect industry best practices and ensure relevance and alignment with 3CE’s goals. 3CE staff is responsible for designing and executing specific plans, metrics, limits, hedging plans, and processes in accordance with the ERMP. 3CE staff will report regularly to the Risk Management Committee (RMC)
3CE aims to achieve these goals by managing the key risks identified in the Risk Catalog in Section 2.2 below. The goals will be incorporated into the specific limits and metrics used to govern hedging activities and long-term procurement. It is important to note these goals are not intended to be a comprehensive list of 3CE’s goals.

To ensure 3CE is implementing best practices for an energy supplier of its size and scope, 3CE will perform an internal risk audit on a selected process or policy annually. Significant findings will trigger an external audit. Notwithstanding, external audits will occur every five years. Audit results will be presented to the RMC.

2.2 Risk Catalog
This Energy Risk Management Policy addresses the following key risks:
a) Customer Opt-Out risk

8 b) Market risk
c) Liquidity risk
d) Regulatory risk
e) Volumetric risk
f) Model risk
g) Operational risk
h) Counterparty & Generalized Credit risk

2.2.1 Customer Opt-Out Risk
Customer opt-out risk includes any condition or event that creates the potential for significant reductions in the CCA’s customer base, leading to the potential of higher retail rates, uncompetitive position, and further loss of customer base. Customer opt-out risk remains a primary risk for the CCA industry. Opt-out risk is managed through:
 Charging competitive retail generation rates, offering innovative energy programs to facilitate electrification, and reducing greenhouse gas (GHG) emissions  Engaging in ethical, transparent and honest business practices  Maintaining financial strength, including an adequate Rate Stability Reserves Fund

2.2.2 Market Risk
Market (energy price) volatility risk is the risk of losses due to the movements in power market prices, interest rates, and credit market prices. Power market price risk includes the risk of adverse price movements in energy, capacity, power basis, renewable attributes, and underlying drivers such as natural gas market prices. Interest rate and credit market price risks are considered when evaluating financing structures associated with long-term hedges or contracts. 3CE will manage market risk through the following:
 Regular measurement, including forward-looking stress tests based on multiple factors and Value-at-Risk (VaR) over multiple time horizons
 Execution of approved procurement
 Hedging and Congestion Revenue Rights strategies
Use of the Limit Structure is set forth in Section 5, below.

2.2.3 Liquidity Risk
Liquidity risk is the risk that 3CE will not be able to meet its short-term cash or financial obligations as they come due. This could occur if 3CE is unable to convert its assets into cash quickly enough to cover its immediate liabilities, or if it cannot secure financing at reasonable terms. 3CE will manage liquidity risk by maintaining sufficient cash reserves, having access to credit facilities, and implementing robust cash flow forecasting and monitoring processes to ensure it can meet its financial obligations and continue operations without disruption.

9 2.2.4 Regulatory and Legislative Risk
3CE and other CCAs are subject to an evolving legal and regulatory landscape. Additionally, CCAs are in direct competition with California’s IOUs in supplying retail electricity, and the IOUs face the risk of stranded investments in generating assets and power purchase agreements procured in the past to serve now departing CCA loads. The way such stranded costs of these legacy power supplies are allocated to departing CCA loads is subject to change based on various proceedings at the California Public Utilities Commission (CPUC). The outcome of such proceedings will directly affect the cost of power for 3CE’s customers, as well as impact the rate competitiveness of 3CE.

In addition to IOU-imposed surcharges, potential regulatory and/or legislative changes could affect the following:
 3CE’s ability to exercise local control over the manner and means of procuring power supplies to serve its customers
 Market prices
 Procurement requirements
 Cash flows
3CE will manage regulatory and legislative risks by the following activities:
 Regularly monitoring and analyzing legislative and regulatory proceedings impacting CCAs  Actively participating in, and advocating for, the interests of 3CE and its customers during regulatory and legislative proceedings

2.2.5 Volumetric Risk
Volumetric risk is the uncertainty in quantity of load served by 3CE. This leads to uncertainty in the amounts of both energy and renewable energy that 3CE must procure for its customers. Volumetric risk may be driven by factors such as attrition, weather, and behind-the-meter generation. Customer opt-out risk is explicitly modeled under this policy. Weather is the biggest short-term driver of volumetric risk. 3CE will develop load distributions that account for a wide range of weather outcomes and size positions accordingly. 3CE may set limits on open positions by tenor, as appropriate, to reduce volumetric risk.

2.2.6 Model Risk
Model risk is variance from modeled or forecasted outcomes due to fundamental deficiencies in models and/or information systems. 3CE will manage model risk by the following means:
 Validating all models on an ongoing basis for robustness, updating and/or enhancing models as needed
 Continually reviewing all model outputs
 Collaborating regularly with vendors, and exchanging information and best practices with peers bilaterally or in trainings and conferences
 Requiring all procurement transactions be recorded in a single trade capture system when that system is available

10 2.2.7 Operational Risk
Operationalrisk is variance in financial performance due to weaknesses or failures in the quality, scope, content, and/or execution of hedging, procurement, and risk management functions. Operational risk also incorporates fraudulent actions by employees or third parties, particularly due to inadequate or ineffective controls. 3CE manages operational risk through a variety of methods:
 Timely and effective reporting to the Chief Executive Officer (CEO) and the RMC  Segregation of functions
 Layered oversight
 Implementation of a compliance training program for all 3CE staff  Ongoing 3CE and consultant staff education/training and participation in industry forums  Annual internal audits to test compliance with the ERMP

2.2.8 Counterparty & Generalized Credit Risk
Counterparty risk is the risk that a counterparty will fail to perform or adequately remedy its obligations in accordance with contractual and transactional terms. Generalized credit risk is the risk of a generalized reduction in credit to a sector, a set of counterparties, or a specific counterparty that results in an increase in counterparty risk. 3CE will monitor counterparty risk based on a variety of metrics and analyses, including but not limited to an in-depth review of counterparty financials when not rated by a credit rating agency, exposure by credit rating, exposure by tenor and product type.

11 SECTION 3: ORGANIZATIONAL STRUCTURE AND RESPONSIBILITIES

3.1 Risk Management Organizational Structure
3CE risk management is organizationally structured to ensure effective segregation of duties and multiple layers of oversight using a waterfall approach. Risk approval limits are contained in Section 9, the Risk Management Delegation of Financial Authority (DOFA).

The 3CE Operations Board of Directors (Operations Board) is responsible for approving this ERMP. It reviews and approves this policy and approves risk exposures above those delegated to the Chief Executive Officer (CEO) or Risk Management Committee (RMC) in the DOFA.

The RMC is responsible for overseeing strategic compliance with this policy and approving risk exposures above those delegated to the CEO.

The Front Office is responsible for the energy short-term trading function and long-term negotiations of power supply contracts, mindful of ERMP limits.

The Middle Office is responsible for ensuring compliance with this ERMP and monthly reporting of risk exposure to the RMC. This segregates the monitoring and trading functions, ensures adherence to risk limits and provides an important check and balance.

The Back Office is responsible for processing payments, ensuring adherence to contract terms and providing appropriate reporting to regulatory agencies.

3.2 Risk Management Committee
The CEO shall establish the RMC, set the agenda, and serve as its Chair. The RMC consists of the following voting members:
 Chief Executive Officer
 Up to five (5) members of 3CE’s Policy and/or Operations Board of Directors, selected by the CEO
 Chief Financial Officer
 Chief Operating Officer
 Chief Communications Officer
The RMC is responsible for overseeing strategic compliance with this ERMP and approving major risk exposures above those delegated to the CEO. This includes ensuring procurements and hedging are consistent with 3CE’s strategic goals.

Specifically, the RMC maintains the authority and responsibility to:
 Ensure that procurements are consistent with this ERMP and hedging plans based on 3CE’s

12 financial objectives and situation
 Approve procurements and risk exposures above those delegated to the CEO and up to the limits specified in the DOFA, based on the strategic goals of this ERMP and 3CE’s financial situation
 Understand and approve the limits, metrics, and product types necessary to ensure compliance with this ERMP
 Review risk management reports as described in this ERMP  Review actual and projected risks and financial outcomes and review summaries of violations of this ERMP
 Refer to the Operations Board those exposures and risks above those delegated to the RMC in the DOFA

3.3 Segregation of Duties
3CE shall maintain a segregation of duties, also referred to as "separation of function,” to help manage and control the risks outlined in this ERMP. Individuals responsible for legally binding 3CE to a transaction will also not perform confirmation or settlement functions without supplemental, transparent, and auditable controls. 3CE will leverage the organizational structure of the Scheduling Coordinator’s Middle and Back offices to help maintain a segregation of duties. The Front, Middle and Back Office responsibilities for 3CE are described below.

3.3.1 Front Office
The Front Office is headed by the Director of Power Supply Resources. The Front Office is responsible for the procurement and hedging activities necessary to manage 3CE’s wholesale power market positions and obligations. Specific responsibilities include:
 Developing long-term procurement strategies to reliably meet 3CE’s load-serving obligation using a least-cost best-fit approach
 Developing annual, quarterly, and monthly hedge plans to prudently meet 3CE’s load-serving obligation using a mix of market transactions and 3CE’s power assets  Optimizing 3CE’s load-supply balance and asset management strategies to prudently maximize value for 3CE customers while adhering to all risk management processes and limits  Overseeing and directing scheduling of load and resources into the CAISO  Developing and using fundamental and probabilistic analysis – such as power market supply-demand balances and transmission outages – to guide optimization, procurement, and hedging decisions
 Accurately recording all transactions in the System of Record  Accurately tracking open forward positions and hedge performance across tenorsfor all power products (energy, renewable energy, carbon-free energy and resource adequacy capacity)  Maintaining forward prices for all illiquid power products (renewable energy credits, carbon-free energy and resource adequacy capacity) in the System of Record  Executing transactions and negotiating or amending contracts as needed to meet the above

13 goals in accordance with the limits set out in the DOFA. Restructuring previously approved transactions and contracts as needed in accordance with the DOFA limitations  Managing and facilitating the transaction execution process for power supply transactions through coordination of the following activities:
a. Notifying Front Office personnel of any anticipated unique physical delivery or scheduling issues
b. Working with Middle Office personnel and legal counsel to establish a contract, evaluate counterparty creditworthiness and secure additional credit from the counterparty, if necessary
c. Working with Middle Office, as needed, to perform an analysis of the potential transaction to evaluate the effects on 3CE’s portfolio risks d. Notifying Back Office of terms and conditions affecting settlement to ensure that the necessary settlement procedures are in place

3.3.2 Middle Office
The Middle Office functions are the responsibility of the Chief Financial Officer. The Middle Office is responsible for implementing, administering, and monitoring compliance with this ERMP. Specific responsibilities include:
 Developing market and transaction analytics that inform risk analyses of 3CE’s hedging and procurement activities, providing Front Office with independent views as needed  Developing metrics and risk management processes for the risks identified in the Risk Catalog in this ERMP
 Designing and setting hedging and procurement limits, including but not limited to product types, tenors, delivery points, counterparties, and markets  Monitoring risk exposures and policy compliance on an ongoing basis, with monthly reporting to the RMC
 Validating all positions, prices, and forecasts in the System of Record  Developing limits with exchanges, brokers, and trading venues  Analyzing risk of the hedging and procurement plans developed by the Front Office  Assisting consultants in developing and maintaining demand forecasts  Developing internal estimates of forward prices used in valuation, pricing and monitoring where credible liquid data is not available
 Assisting in expert valuation of all 3CE positions and contracts  Supporting settlement validation, as necessary
 Reporting limit violations to the RMC
 Validating the net forward power positions of 3CE
 Assist Back Office in calculating Counterparty Credit Exposure

14 3.3.3 Back Office
The Back Office is responsible for the administrative activities necessary to execute and settle transactions and contracts and to support the Middle Office where necessary to monitor compliance with this ERMP.

Specific responsibilities include:
 Confirming all transaction details (physical and financial) and reconciling differences with the trading counterparties
 Reviewing transaction confirmations for adherence to approved limits  Validating trade entry and flow through the System of Record  Validating and reconciling physical and financial transaction flows  Settling trades and calculating revenues and profit & loss  Providing settlement, credit, and other data as needed to the Middle Office and Finance to support monitoring of risk exposures and budget processes  Validating and promptly paying of energy related invoices payable by 3CE and resolving disputes with counterparties
 Generating and promptly collecting energy related invoices payable by counterparties

15 SECTION 4: BUSINESS PRACTICES

4.1 General Conduct
All personnel, including Members of the Operation and Policy Board of Directors, staff, and agents, (collectively referred to “3CE Representatives”) adhere to standards of integrity, ethics, conflicts of interest, compliance with statutory law and regulations and with applicable 3CE standards of personal conduct while employed by, contracted by, or affiliated with 3CE.

4.2 Hedging & Trading Activities; Prohibition on Speculation 3CE contracts and trades in energy markets to hedge positions, reduce risk, and, in compliance with this ERMP, prudently optimize the value of its portfolio of assets and market positions. Speculative trading is explicitly prohibited under this ERMP. Examples of speculative trading include trading a commodity for which 3CE does not have an underlying position or risk, trading a product based solely on personal judgement about future market direction, taking positions in volumes that deviate significantly from 3CE’s underlying need, etc. Should a question arise about speculative trading activities, 3CE’s Middle Office will make an initial finding based on an analysis of the situation and present a written report to the RMC. The RMC will make a final determination based on the situation.

4.3 Trading for Personal Accounts
All 3CE staff and agents are prohibited from trading the power and environmental products traded by 3CE for personal accounts.

4.4 Conflict of Interest
3CE staff are expected to meet the highest standards for ethical conduct, beyond just the specific matters discussed in this section.
3CE staff responsible for negotiating, reviewing, and/or approving hedging activities and procurements are obligated to provide written notice to 3CE of any real or potential conflict of interest in the matter.

An example of such a conflict of interest may be negotiating with a counterparty while seeking employment for oneself or a relative with that counterparty. 3CE staff are prohibited from trading on information gained during hedging and procurement activities.

An example of such an activity would be a 3CE employee directly or indirectly purchasing stock in a developer prior to the announcement of 3CE awarding that developer a significant contract. Purchases of pooled vehicles such as broadly diversified mutual funds and ETFs are exempted from this ERMP. 3CE Front Office staff are expected to seek best execution and least-cost best-fit product attributes from counterparties and intermediaries. Steering trades and contracts to counterparties based on potential financial gain or personal relationships is prohibited.

16 Additionally, Conflicts of Interest shall be identified and defined as set forth in the 3CE Conflict of Interest Code, as amended from time to time by the Policy Board, which incorporates the Political Reform Act requirements for all employees advising 3CE.

If there is any doubt as to whether a prohibited condition exists, then it is the Representative’s responsibility to discuss the possible prohibited condition with 3CE General Counsel. Employees may seek an advisory position from the California Fair Political Practices Commission.

4.5 Adherence to Statutory Requirements
Compliance is required with rules promulgated by the state of California, California Public Utilities Commission (CPUC), California Energy Commission (CEC), Federal Energy Regulatory Commission (FERC), Commodity Futures Trading Commission (CFTC), and other regulatory agencies.

Congress, the FERC and the CFTC have enacted laws, regulations and rules that prohibit, among other things, any action or course of conduct that actually or potentially operates as a fraud or deceit upon any person in connection with the purchase or sale of electric energy or transmission services. These laws also prohibit any person or entity from making any untrue statement of fact or omitting to state a material fact where the omission would make a statement misleading. Violation of these laws can lead to both civil and criminal actions against the individual involved, as well as 3CE. This ERMP is intended to comply with these laws, regulations, and rules and to avoid improper conduct on the part of anyone employed by 3CE. These procedures may be modified from time to time due to legal requirements, auditor recommendations, RMC requests and other considerations.

In the event of an investigation or inquiry by a regulatory agency, 3CE may provide legal counsel to employees. However, 3CE, with the consent of the Operations Board, will not appoint legal counsel to an employee if 3CE determines that representation of the employee will create an actual conflict between the employee and 3CE, or that the employee was not acting in good faith within the scope of employment.

4.6 Authorized Products, Markets & Terms
Transactions are conducted bilaterally, using standard contracts under previously executed counterparty enabling agreements such as the Edison Electric Institute’s Master Power Purchase & Sale Agreement (EEI) or Western Systems Power Pool’s Agreement (WSPP), or through exchanges such as the InterContinental Exchange (ICE). 3CE’s CEO, or their designee, must authorize all counterparty enabling agreements as well as all individual transactions.

New products, tenors, markets, delivery points, and transaction types can be authorized by the RMC.

When seeking such approval, a New Product Approval Form, as shown in Appendix C, should be drafted describing all significant elements of the proposed product. This should include, at a minimum:
 A description of the benefit to 3CE, such as decreasing costs, managing volatility etc.  The role of the new product in 3CE’s overall portfolio and risk management strategies

17  Risk analysis that identifies the specific risks mitigated by the new product and illustrates its application
 Transaction process, initial risk limits and settlement process  Proposed valuation methodology (including pricing model, where appropriate)  Proposed accounting methodology
3CE’s CEO or their designee is responsible for requesting the RMC’s approval. If approved, Appendix A to the Policy will be updated to reflect the new transaction type

4.7 System of Record
3CE will maintain a secure set of records for all transactions executed in association with 3CE procurement activities. 3CE’s Technology and Data & Analytics group supports the security, integrity, and recoverability of the System of Record. For data recoverability, transaction data stored in the System of Record is replicated daily to ensure data redundancy and is backed-up via cloud-based applications.

The records will be maintained in US dollars and transactions will be separately recorded and categorized by type of transaction. This system of record shall be auditable and audited as appropriate.

4.8 Transaction Valuation
Transaction valuation and reporting of positions shall be based on objective, market-observed prices.

Whenever possible, mark-to-market valuations should be based on independent, publicly available market information and data sources. The Middle Office will be responsible for independently validating and reporting marks and valuations.

4.9 Policy Compliance
The Middle Office will provide a monthly report to the RMC monitoring compliance with the limits established by the ERMP.

18 SECTION 5: TOLERANCES

5.1 Hedging Tolerances
Hedging tolerances for energy, renewable attributes, capacity (resource adequacy) and carbon-free energy are shown below. From time to time, the Middle Office, in response to market conditions, may recommend adjustments to these ranges.

While 3CE is generally a purchaser of energy and related products, there are instances in which staff might wish to rebalance the portfolio through the sale of contracts or other market products, as appropriate, in order to realign exposures with the agency’s risk tolerances and policy objectives. All such actions will be conducted in accordance with this Policy and the applicable Delegation of Authority.

5.1.1 Energy Procurement Tolerances
Fixed Price Energy purchases provide for suppliers to deliver energy – for which 3CE will receive energy market revenues – to 3CE at a fixed price. They are used to manage the electricity commodity price risk that 3CE faces as a Load Serving Entity. Specific to 3CE ‘s customers, Fixed Price Energy hedges are used to provide cost certainty and rate stability.
3CE predominantly employs Fixed Price Block Energy contracts, which provide for suppliers to deliver a predetermined volume of energy at a constant delivery rate. As 3CE enters into long-term, fixed price contracts for renewable and/or carbon-free energy, these will likewise hedge 3CE’s market risk and, subsequently, reduce the required volume of Fixed Price Block Energy purchases.

When assessing its requirements for Fixed Price Energy, 3CE will use an econometric model to forecast hourly energy requirements and monthly peak demand by customer load class. The model will use historical data to estimate relationships between energy consumption and economic, demographic and/or weather variables. The model will be refined through time as additional load and other data is acquired.
3CE will observe the following schedule when hedging its Fixed Price Energy Requirements. The Minimum and Maximum hedge % represent the Fixed Price Energy planned or under contract divided by forecasted wholesale load.

Quarter
Minimum
Hedge %
Maximum
Hedge %
Prompt Q
(PQ) 85% 110%
PQ + 1 80% 110%

19 PQ + 2 74% 110%
PQ + 3 69% 110%
PQ + 4 63% 105%
PQ + 5 58% 99%
PQ + 6 52% 93%
PQ + 7 47% 87%
PQ + 8 41% 82%
PQ + 9 36% 76%
PQ + 10 -
15 30% 70%
Notwithstanding the maximum hedge levels shown in the above table, there shall be no maximum hedge level in quarters in which 3CE only owns long-term power purchase agreements and energy storage agreements.

Energy hedging compliance will be measured within 5 days prior to the first day of each quarter (e.g., on a date between September 26th and September 30th, 2024, 3CE will have hedged 85 to 110 percent of its projected energy requirements for Q4 2024 and 80 to 110 percent of requirements for Q1 2025).

The minimum hedge level will be achieved by implementing a time-driven programmatic strategy.

Time-driven programmatic hedges are executed at a predetermined rate pursuant to a time schedule and without regard for market conditions. The purpose of these hedging transactions is to achieve a reduction in variability in power supply costs by gradually increasing the amount of energy hedged as the actual date of consumption approaches. Time-driven strategies avoid the inherent impossibility of trying to consistently and accurately “time the market” to purchase energy at least cost when making hedging decisions. Additionally, a load serving entity the size of 3CE needs to spread its procurement efforts over time to effectively manage the potential negative price impacts of procuring a large volume of energy, over a short period of time, in an illiquid market.

Hedging decisions to reach targets between the minimum and maximum hedge levels will be based on price-driven or opportunistic strategies. The purpose of price-driven or opportunistic strategies is to capitalize on market opportunities when conditions are favorable. 3CE will base its decision to execute opportunistic hedges on the anticipated impact to projected power supply costs and the resulting reduction in risk.

Opportunistic hedges may be executed when energy price levels are favorable to lowering the cost of power relative to established program goals and financial projections; alternatively, opportunistic

20 hedges can be executed in adverse market conditions relative to financial goals in order to reduce the potential negative impact of continued upward trending commodity prices relative to established goals.

In executing this energy risk hedging strategy, Fixed-Price Energy hedges may be modified, repositioned or unwound for the purpose of maintaining hedge coverage that matches changes in forecast electric load or supply. This includes the ability of 3CE to use liquid market products to hedge average loads over a defined time period and then later modify its hedges to more precisely match load.

5.1.2 Renewable Energy Procurement Tolerances
In order to cost-effectively meet its GHG-reduction and renewable energy goals, 3CE intends to meet a growing share of its energy supply requirements with renewable energy, a large portion of which will be Product Content Category 1 (PCC1) renewable energy. PCC1 renewable energy is sourced from a renewable generator that is either directly interconnected to the California Independent System Operator (CAISO) or another California Balancing Authority or directly scheduled into CAISO without use of substitute energy. 3CE may diversify its renewable energy portfolio further by incorporating Portfolio Content Category 2 (PCC2) renewable energy purchases. PCC2 renewable energy is sourced from renewable generators located outside the state of California, where that generation is “firmed and shaped” for delivery into California. PCC2 purchases are typically less expensive and shorter in term than PCC1, so they provide a cost-effective and flexible method of augmenting 3CE’s renewable energy purchases to meet renewable portfolio content commitments to customers. However, not all PCC2 renewable energy is emissions-free; therefore, 3CE must assess the value of PCC2s against its respective emissions intensity. In addition, RPS compliance rules set minimum requirements for PCC1 and PCC2 as a percentage of the total RPS compliance portfolio, which 3CE will abide by in its procurement of both products.

In order to manage price risk of long-term renewable energy, and to allow 3CE to prudently and methodically build a portfolio of long-term assets, 3CE intends to meet its renewable energy targets with a blend of short- and long-term contracts. 3CE intends to fully comply with long-term contracting requirements mandated by SB 100; therefore, executed and planned long-term renewable contracts will be reflected in 3CE’s renewable energy positions.
3CE shall observe the following schedule while hedging its SB 100 annual minimum renewable energy requirements. The minimum hedge percentages specified shall be measured during the final five days of each calendar year, based on the applicable renewable energy vintage for each compliance year.

21 Measurement
Year (as of final
five days)
2025 Vintage
Minimum
Hedge (%)
2026 Vintage
Minimum
Hedge (%)
2027+ Vintage
Minimum Hedge
(%)
2025 100 90 90
2026 100 100 90
2027 — 100 100 (2027 Vintage)
2028 — — 100 (2028 Vintage)
2029 — — 100 (2029 Vintage)
2030 — — 100 (2030 Vintage)

5.1.3 Capacity Procurement Tolerances
As a Load-Serving Entity (LSE) in California, 3CE is required to demonstrate both annually and monthly that it has secured sufficient energy capacity to provide for its share of California’s energy load; this capacity is referred to as resource adequacy (RA).

RA is typically transacted via contracts that vary in length, and it is currently bought and sold via a bilateral market. This market provides cost-effective contracting opportunities, but also proves at times to be fragmented and volatile. It is the goal of 3CE to meet all RA requirements, including local, flexible, and system requirements.
3CE will observe the following schedule when hedging its year-ahead RA requirements. The hedge schedule shall be measured for the system RA product by month that 3CE is required to procure within 5 days prior to December 1 of each year for the Prompt Calendar Year and the four subsequent calendar years.

Time Period Minimum Hedge %
(applicable to the shortest hour
of each month)
Maximum Hedge %
(applicable to shortest hour of
peak month only)2
Prompt Calendar Year 90 100
PY + 1 50 95

2 Due to the variable nature of 3CE’s monthly RA requirements, non-peak months may exceed the applicable Maximum Hedge %.

22 PY + 2 35 90
PY + 3 35 80
PY + 4 35 80
Month-ahead system and flexible RA requirements will be met with the required monthly CPUC filing.

5.1.4 Carbon-Free Energy Tolerances
3CE may have the opportunity to receive free carbon-free energy allocations from PG&E and SCE at zero cost. Hedging activity should consider these allocations and expected allocations should be included in the hedging percentages.
3CE will observe the following schedule when hedging its carbon-free renewable energy requirements.

This hedge schedule shall be measured within 5 days prior to the first day of each quarter for the Current Calendar Year, and within 5 days prior to December 1 of each year for the following ten Calendar Years.

Time Period Minimum Hedge % Maximum Hedge %
Current Calendar Year 85 110*
Prompt Calendar Year 75 110*
PY + 1 50 110
PY + 2 25 100
PY + 3 0 75
PY + 4 - 9 0 75
* Maximum hedge percentages allow for a planning margin to accommodate volumetric uncertainty associated with electric consumption and generation In setting the above targets, it is important to note that the purchase of carbon-free energy is a voluntary requirement set by the 3CE Board to exceed states’ GHG emissions goals. In determining the total volume of carbon-free energy to be hedged, the 3CE Board may elect to increase or reduce the total quantity of carbon-free energy included in 3CE’s portfolio as it seeks to balance multiple program objectives, including financial goals such as targets for financial reserves and retail rates.

5.1.5 Congestion Revenue Rights (CRRs)
As a CAISO market participant, 3CE has congestion risk associated with serving its customer load. 3CE

23 manages congestion risks by preferring day ahead scheduling of energy delivered at NP-15 and SP-15, and by resource assessment and selection consistent with this ERMP. Once energy is procured, 3CE manages congestion risk through the prudent management of CRRs, which are financial instruments used to hedge against transmission congestion costs encountered in the CAISO day-ahead market. The RMC is responsible for overseeing the management of CRRs and CRR trading. The CRR portfolio will be managed by 3CE 's Front Office with support from 3CE’s Scheduling Coordinator. CRRs are transacted to effectively manage portfolio congestion risk, through hedging and value maximization. Trading of CRRs for speculative purposes is not permitted.

CRR position restriction: 3CE shall not use the annual or monthly CRR auctions to do any of the following:
 Increase CRR holdings on paths not related to 3CE’s generation, storage or inter-scheduler trades (ISTs)3
 Increase CRR holdings above expected generation, discharge or IST volumes on paths related to 3CE’s generation, storage or ISTs

5.2 Monitoring, Reporting and Instances of Exceeding Risk Limits The Middle Office is responsible for monitoring, and reporting compliance with, all limits within this ERMP. If a limit or control is violated, the Middle Office will notify the RMC. The RMC will discuss the cause and potential remediation of the exceedance to determine next steps for curing the exceedance.

3 Inter-scheduler trades source at NP-15. In addition to purchasing CRRs at NP-15, 3CE may additionally purchase CRRs on paths that have been found to be good proxies for NP-15.

24 SECTION 6: CREDIT POLICY
Counterparty and generalized credit risk are significant risks to 3CE’s financial operations. The Middle Office will conduct a thorough analysis of all candidate counterparties prior to approving them to transact. This analysis will include but not be limited to analyzing the proposed counterparty’s financial statements (if unrated), credit rating, liquidity, hedge levels, market sensitivity, and business operations. The Middle Office will determine whether to extend an unsecured or secured credit line to the candidate counterparty, as appropriate. The maximum unsecured credit line that can be extended to any counterparty is $50 Million.

In addition to individual counterparty limits, the Middle Office will set limits by credit rating, tenor, product, and, where appropriate, transaction type and delivery type. For example, it may set an overall limit of $50 million for counterparties rated BB+ that supersedes the BB+ counterparties’ individual credit approvals of $100 million. This will limit the concentration of credit risk.

Counterparty credit health and generalized credit conditions will be monitored on an ongoing basis.

Individual counterparty limits or aggregate credit limits by tenor/product/credit rating may be adjusted up or down to reflect current conditions. Counterparties who exceed limits must promptly post enough collateral to come into compliance or risk having their positions liquidated.

25 SECTION 7: POSITION TRACKING AND MANAGEMENT REPORTING Minimum reporting requirements are shown below. The reports outlined below will be made available to RMC members:
 Monthly Financial Model Forecast
Latest projected financial performance, marked to current market prices, and shown relative to financial goals
 Monthly Net Position Report
Latest forward net position reports of all product classes  Monthly Counterparty Credit Exposure
Credit exposures for transactions executed by 3CE
 Monthly Risk Analysis
To include a stress test of financial forecast relative to financial goals

26 SECTION 8: POLICY REVISION PROCESS
3CE’s Energy Risk Management Policy (ERMP) will evolve over time as market and business factors change. At least on an annual basis, the RMC will review the ERMP and associated procedures to determine if they should be amended, supplemented, or updated to account for changing business and/or regulatory requirements. If an amendment is warranted, the ERMP amendment will be submitted to the 3CE Operations Board for approval. Changes to appendices to this ERMP may be approved by the RMC.

8.1 Acknowledgement of Policy
Any 3CE employee participating in any activity or transaction within the scope of the ERMP shall sign on an annual basis or upon any revision, a statement approved by the RMC that such employee:
 Read 3CE’s ERMP
 Understands the terms of said ERMP
 Will comply with said ERMP
 Understands that any violation of said ERMP shall be subject to employee discipline up to and including termination of employment

8.2 Policy Interpretations
Questions about the interpretation of any matters of this ERMP should be referred to the CEO. All legal matters stemming from this ERMP will be referred to General Counsel.

27 SECTION 9: DELEGATION OF FINANCIAL AUTHORITY
The Policy and Operations Boards of Directors (Boards) explicitly delegates approval of transactions to the CEO and the RMC as outlined in the following table:

Position Maturity Limit Term Limit Value Limit ($)1
Risk Management Committee 96 Months 60 Months 110,000,000 Chief Executive Officer 96 Months 60 Months 65,000,000
1 “Value Limit” is the total notional value of the transaction, inclusive of any related procurement fees.

These delegated authorities may be further delegated and used to set hedging and procurement limits necessary to manage 3CE’s portfolio. For example, the CEO could authorize the Front Office to trade up to the CEO’s authority limits in approved products.

Additionally, to adapt to changing market conditions and to facilitate the daily operations of 3CE, the Boards have delegated authority to the CEO (or designee) to execute administrative amendments to duly approved transactions where such amendments do not exceed the CEO’s delegated authority as set forth above (for clarity, amendments exceeding Maturity, Term or Value limits shall require Operations Board approval) and further reduces 3CE’s risk in furtherance of this ERMP. Such administrative amendments must be reported during the next RMC meeting and Operations Board meeting.

These authorities will be applied to wholesale power activity executed outside of the California Independent System Operator (“CAISO”) markets. These limits provide 3CE needed authorities to manage risks as they arise. Transactions falling outside the delegations above require Board approval prior to execution. Activity with CAISO is excluded from this table due to the nature of the market, where prices for activity may not be known until after transactions are committed.

All procurement executed under the delegation above must align with the 3CE’s underlying risk exposure (locational, volume and temporal) that is being hedged consistent with the approved Procurement Strategy.

The point of delivery for all products must be at a location on the CAISO transmission grid.

28 Appendix A: AUTHORIZED TRANSACTION TYPES, REGIONS, AND MARKETS All transaction types listed below must be executed within the limits set forth in this ERMP.

Over the Counter Products
 CAISO Market Products
o Day-ahead and Real-time Energy
o Congestion Revenue Rights
o Convergence bids
o Inter Scheduling Coordinator Transactions
o Tagging into and out of CAISO
 Physical Power Products
o Power
o Physical Over-the-counter Options
o Physical Resource Adequacy Capacity
 Import Capability Rights
 Physical Transmission Products
o Physical WECC Transmission
 Physical Environmental Products
o Renewable Energy Credits
o Specified Source Power
o Carbon Allowances and Obligations
 Financial Power Products
o Power
o Financial Over-the-counter Options
 Physical Natural Gas Products
o Firm or interruptible natural gas supply contracts
o Swing supply contracts (daily or monthly flexibility) o Physical delivery at trading hubs (e.g., SoCal Border, SoCal Citygate, PG&E Citygate, Malin, etc.)
 Financial Natural Gas Products
o Fixed-for-floating swaps (e.g., Henry Hub, SoCal Citygate, PG&E Citygate) o Basis swaps (e.g., Henry Hub vs. SoCal Citygate, Henry Hub vs. PG&E Citygate) o Financial futures and forwards (e.g., NYMEX Henry Hub)  Broker Fees

29 Appendix B: NEW TRANSACTION APPROVAL FORM
New or Non-Standard Transaction Approval Form
Prepared By:

Date:

New or Non-Standard Transaction Name:

Business Rationale and Risk Assessment:
 A description of the benefit to 3CE, such as decreasing costs, managing volatility etc.  The role of the new product in 3CE’s overall portfolio and risk management strategies  Middle Office risk analysis that identifies the specific risks mitigated by the new product and illustrates its application
 Transaction process, initial risk limits and settlement process  An assessment of the legal, tax, and regulatory aspects of the product  Proposed valuation methodology (including pricing model, where appropriate)  Proposed reporting requirements, including any changes to existing procedures and system requirements necessary to support the new transaction type  Proposed accounting methodology
Reviewed by:

30 Appendix C: DEFINITIONS
Back Office: That part of a trading organization which handles transaction accounting, confirmations, management reporting, contract administration and working capital management, which reports to the Chief Operating Officer.

Bilateral Transaction: Any physical or financial transaction between two counterparties, neither of whom is an Exchange or market entity such as CAISO.

Cash Flow at Risk: A measure of the potential shortfall in cash flow from a specified level during a specified period of time at a specified confidence level.

CAISO: California Independent System Operator. CAISO operates a California bulk power transmission grid, administers the State’s wholesale electricity markets, and provides reliability planning and generation dispatch.

California Energy Commission (CEC): CEC is the primary energy policy and planning agency for California.

California Fair Political Practices Commission (FPPC): FPPC is a five-member independent, non-partisan commission that has primary responsibility for the impartial and effective administration of the Political Reform Act.

California Public Utilities Commission (CPUC): CPUC is a regulatory agency that regulates privately owned public utilities in the state of California, including electric power, telecommunications, natural gas and water companies.

Community Choice Aggregator (CCA): CCAs allow local government agencies such as cities and/or counties to purchase and/or develop generation supplies on behalf of their residents, businesses, and Chief Operating Officer Date
Chief Financial Officer Date
General Counsel Date
Chief Executive Officer Date

31 municipal accounts.

Commodity Futures Trading Commission (CFTC): The CFTC is a U.S. federal agency that is responsible for regulating commodity futures and swap markets. It goals include the promotion of competitive and efficient futures markets and the protection of investors against manipulation, abusive trade practices and fraud.

Clearing: Clearing is the process of reconciling purchases and sales of a commodity, as well as the direct transfer of funds from one financial institution to another. The process validates the availability of funds, records the transfer, and in the case of financial securities, ensure the delivery to the buyer.

Commodity: A basic good used in commerce that is interchangeable with other commodities of the same type. Commodities aremost often used asinputsin the production of other goods orservices. The quality of a given commodity may differ slightly, but it is essentially uniform across producers. When they are traded on an exchange, commoditiesmust alsomeetspecifiedminimum standards, also known as a basis grade.

Confirmation Letter: A letter agreement between two counterparties that details the specific commercial terms (e.g., price, quantity and point of delivery) of a transaction.

Congestion Revenue Right: A point-to-point financial instrument in the Day-Ahead Energy Market that entitles the holder to receive compensation for or requires the holder to pay certain congestion related transmission charges that arise when the transmission system is congested.

Counterparty Credit Risk: The risk of financial loss resulting from a counterparty to a transaction failing to fulfill its obligations.

Counterparty Credit Exposure: This measures the known exposures and is represented by the sum of both (a)Realized exposure and (b) Forward exposure, as those terms are defined below:

Realized exposure: payable or receivable amount owed between counterparties, is a measurement of cash flow for billed and unbilled transactions.

Forward exposure: measure of current unrealized exposure and includes the measure of a counterparty’s incentive to fulfill contractual obligations. Forward exposure measures the risk associated with having a payment default or the need to replace a transaction in the event of delivery default.

Edison Electric Institute (EEI): EEI is an association that represents all U.S. investor-owned electric companies.

Day-ahead Market: The short-term forward market for efficiently allocating transmission capacity and facilitating purchases and sales of energy and scheduled bilateral transactions; conducted by CAISO prior to the operating day.

Delivery point: the point at which a commodity will be delivered and received.

Federal Energy Regulatory Commission (FERC): FERC is a federal agency that regulates the interstate transmission of electricity, natural gas, and oil. FERC also reviews proposals to build liquefied natural gas terminals, interstate natural gas pipelines, as well as licenses hydroelectric generation projects.

Front Office: That part of a trading organization which solicits customer business, services existing customers, executes trades and ensures the physical delivery of commodities, which reports to the Chief Operating Officer.

Hedging products: Hedging products means capacity, energy, renewable energy credits or other products related to a specific transaction.

32 Hedging Transaction: A transaction designed to reduce the financial exposure of a specific outstanding position or portfolio; “fully hedged” equates to complete elimination of the targeted risk and “partially hedged” implies a risk reduction of less than 100%.

InterContinental Exchange (ICE): ICE s an American company formed in 2000 that operates global financial exchanges, clearing houses and provides mortgage technology, data and listing services.

Investor-Owned Utility (IOU): An IOU is a business organization providing electrical and/or natural gas services to both retail and wholesale consumers and is managed as a private enterprise. Pacific Gas & Electric Company (PG&E) and Southern California Edison (SCE) are examples of IOUs.

Middle Office: That part of a trading organization that measures and reports on market risks, develops risk management policies and monitors compliance with those policies, manages credit, and keeps management and the Board informed on risk managementissues, which reports to the Chief Financial Officer.

Speculation: Speculation is the act of trading an asset with the expectation of realizing financial gain resulting from a change in price in the asset being transacted.

Value-at-Risk (VaR): VaR is a risk tolerance metric that quantifies the extent of possible financial losses within a firm, portfolio, or position over a specific time frame.

Western Systems Power Pool (WSPP): WSPP is an organization of electrical wholesale market entities that have developed and utilize a standardized agreement (WSPP Agreement) to execute trading opportunities, allowing WSPP members to manage power delivery and price risk.

33

1 Energy Risk
Management Policy
(ERMP)
Sixth Revision November 2025 – Operations Board of Directors Approved Fifth Revision October 2024 – Operations Board of Directors Approved Fourth Revision August 2023- Risk Management Committee Approved Third Revision August 2022 – Operations Board of Directors Approved Second Revision November 2020 –Operations Board of Directors Approved First Revision September 2018 –Operations Board of Directors Approved Initial Version March 2018 –Policy Board of Directors Approved

2 Table of Contents
Table of Contents
SECTION 1: ERMP OVERVIEW .......................................................................................................................5

1.1 Background and Purpose ....................................................................................................................5

1.2 Scope...................................................................................................................................................5

1.3 Energy Risk Management Objective ...................................................................................................6

1.4 Policy Administration..........................................................................................................................6 SECTION 2: GOALS AND RISK EXPOSURES ....................................................................................................7

2.1 ERMP Goals.........................................................................................................................................7

2.2 Risk Catalog.........................................................................................................................................7

2.2.1 Customer Opt-Out Risk ................................................................................................................8

2.2.2 Market Risk ..................................................................................................................................8

2.2.3 Liquidity Risk ................................................................................................................................8

2.2.4 Regulatory and Legislative Risk....................................................................................................9

2.2.5 Volumetric Risk ............................................................................................................................9

2.2.6 Model Risk....................................................................................................................................9

2.2.7 Operational Risk.........................................................................................................................10

2.2.8 Counterparty & Generalized Credit Risk....................................................................................10 SECTION 3: ORGANIZATIONAL STRUCTURE AND RESPONSIBILITIES ..........................................................11

3.1 Risk Management Organizational Structure.....................................................................................11

3.2 Risk Management Committee ..........................................................................................................11

3.3 Segregation of Duties........................................................................................................................12

3.3.1 Front Office ................................................................................................................................12

3.3.2 Middle Office..............................................................................................................................13

3.3.3 Back Office .................................................................................................................................14 SECTION 4: BUSINESS PRACTICES ...............................................................................................................15

4.1 General Conduct ...............................................................................................................................15

4.2 Hedging & Trading Activities; Prohibition on Speculation................................................................15

3 4.3 Trading for Personal Accounts..........................................................................................................15

4.4 Conflict of Interest ............................................................................................................................15

4.5 Adherence to Statutory Requirements.............................................................................................16

4.6 Authorized Products, Markets & Terms............................................................................................16

4.7 System of Record ..............................................................................................................................17

4.8 Transaction Valuation .......................................................................................................................17

4.9 Policy Compliance .............................................................................................................................17 SECTION 5: TOLERANCES ............................................................................................................................18

5.1 Hedging Tolerances.........................................................................................................................18

5.1.1 Energy Procurement Tolerances................................................................................................18

5.1.3 Capacity Procurement Tolerances...........................................................................................21

5.1.4 Carbon-Free Energy Tolerances.................................................................................................22

5.1.5 Congestion Revenue Rights (CRRs) ...........................................................................................22

5.2 Monitoring, Reporting and Instances of Exceeding Risk Limits........................................................23 SECTION 6: CREDIT POLICY..........................................................................................................................24 SECTION 7: POSITION TRACKING AND MANAGEMENT REPORTING ..........................................................25 SECTION 8: POLICY REVISION PROCESS ......................................................................................................26

8.1 Acknowledgement of Policy..............................................................................................................26

8.2 Policy Interpretations........................................................................................................................26 SECTION 9: DELEGATION OF FINANCIAL AUTHORITY.................................................................................27 Appendix A: AUTHORIZED TRANSACTION TYPES, REGIONS, AND MARKETS .............................................28 Appendix B: NEW TRANSACTION APPROVAL FORM ..................................................................................29 Appendix C: DEFINITIONS ...........................................................................................................................30

4

5 SECTION 1: ERMP OVERVIEW

1.1 Background and Purpose
Central Coast Community Energy (3CE), formerly Monterey Bay Community Power Authority, is a public Joint Powers Authority (JPA) located within the geographic boundaries of Monterey, Santa Cruz, San Benito, San Luis Obispo and Santa Barbara Counties. Member agencies of 3CE include the Counties of Monterey, San Luis Obispo, Santa Cruz, San Benito, and Santa Barbara, as well as certain incorporated cities located within the member counties1. 3CE members elected to implement and administer a community choice aggregation (“CCA”) program.

The CCA program provides its members an opportunity to procure electricity supplies and implement local programs that meet the goals of the local communities. Electricity procured to serve customers will continue to be delivered over the Investor-Owned Utilities’ (PG&E & SCE) transmission and distribution systems.
3CE exists to serve its local government members, and the residences and businesses located within their respective communities. 3CE’s specific objectives are to lower greenhouse gas (GHG) emissions by reliably supplying its customers with electricity sourced from clean and renewable generation resources at competitive rates along with innovative electrification programs. 3CE also functions to stimulate the local economy and give its member agencies greater choice in the energy procured for their residents.

Providing retail electric generation service to customers enrolled in the CCA program exposes 3CE, and ultimately the customers it serves, to various significant but manageable risks. The intent of this Energy Risk Management Policy (ERMP) is to provide 3CE, and by extension its customers, with a framework to identify, monitor and manage risks associated with procuring power supplies and operating in wholesale energy markets.

This Energy Risk Management Policy, including its appendices, establishes 3CE’s Energy Risk Management Program.

1.2 Scope
Unless otherwise explicitly stated in this ERMP orotherpolicies approved by the appropriate 3CE Board, this ERMP applies to all power procurement and related business activities that may impact the risk profile of 3CE. This ERMP documents the framework by which 3CE staff and consultants will:
 Identify, quantify and manage risk
 Develop and execute procurement strategies

1 Presently, all cities within the five County footprint are 3CE members, with the exception of King City, Lompoc, and the City of Santa Barbara. 3CE will begin serving customers in Atascadero and the unincorporated portions of San Luis Obispo County in January 2025.

6  Develop a framework of controls and oversight
 Monitor, measure, and report on the effectiveness of the ERMP To ensure its successful operation, 3CE may partner with experienced consultants to provide power supply services when appropriate. Specific to power procurement, 3CE has partnered with two third-party Scheduling Coordinatorsthat augment 3CE’s internal Front (scheduling), Middle (monitoring) and Back (settlement) Offices related activities as discussed at Section 3.3. The Scheduling Coordinators, as well as all other consultants supporting 3CE’s power procurement activities, will adhere to and be governed by this ERMP in providing these services to 3CE. In addition, Scheduling Coordinators’ and other consultants’ activities executed on 3CE’s behalf will be governed by their own internal risk management policies and procedures, and prudent industry practices.

1.3 Energy Risk Management Objective
The objective of this ERMP is to provide a framework for conducting procurement activities that will facilitate risk management in an effort to meet 3CE’s goals as listed in Section 2.1.

Pursuant to this ERMP, 3CE will identify and measure the magnitude of the risks to which it is exposed and take the necessary steps to manage and reduce those risks to acceptable levels.

1.4 Policy Administration
This ERMP shall be reviewed and approved at least annually by the 3CE Operations Board of Directors (Board). The Risk Management Committee (RMC) and Operations Board must approve amendments to the ERMP, except for the appendices, which may be amended with approval of only the RMC. The RMC must give timely notice to the Board of any amendment it makes to an appendix or a reference policy or procedure document.

7 SECTION 2: GOALS AND RISK EXPOSURES

2.1 ERMP Goals
3CE operates in dynamic, volatile environments and markets. Prices for energy and its underlying drivers, such as natural gas, are susceptible to unpredictable and sometimes significant changes in short intervals. Regulatory and legislative actions can structurally change markets, market price levels, and procurement requirements. Low liquidity and financial dislocations may lead to counterparty distress. 3CE’s Energy Risk Management Policy (ERMP) is designed to address these challenges. Its overarching goals are the following:
 Preserving the financial health and stability of 3CE
 Providing rate stability
 Ensuring the long-term viability of 3CE
In furtherance of these goals 3CE strives to:
 Maintain a credit rating of A- or equivalent, as defined by S&P Global Ratings or an equivalent ratings agency
 Limit power supply cost variance to the annual budget to 10%, barring extraordinary circumstances
 Fund its Rate Stabilization Fund at levels that buffer customers from rate shock and maintain a competitive market position
The ERMP is a strategic document, not a prescriptive manual. The metrics, limits, and products used to measure and manage risk must continuously evolve to reflect industry best practices and ensure relevance and alignment with 3CE’s goals. 3CE staff is responsible for designing and executing specific plans, metrics, limits, hedging plans, and processes in accordance with the ERMP. 3CE staff will report regularly to the Risk Management Committee (RMC)
3CE aims to achieve these goals by managing the key risks identified in the Risk Catalog in Section 2.2 below. The goals will be incorporated into the specific limits and metrics used to govern hedging activities and long-term procurement. It is important to note these goals are not intended to be a comprehensive list of 3CE’s goals.

To ensure 3CE is implementing best practices for an energy supplier of its size and scope, 3CE will perform an internal risk audit on a selected process or policy annually. Significant findings will trigger an external audit. Notwithstanding, external audits will occur every five years. Audit results will be presented to the RMC.

2.2 Risk Catalog
This Energy Risk Management Policy addresses the following key risks:
a) Customer Opt-Out risk

8 b) Market risk
c) Liquidity risk
d) Regulatory risk
e) Volumetric risk
f) Model risk
g) Operational risk
h) Counterparty & Generalized Credit risk

2.2.1 Customer Opt-Out Risk
Customer opt-out risk includes any condition or event that creates the potential for significant reductions in the CCA’s customer base, leading to the potential of higher retail rates, uncompetitive position, and further loss of customer base. Customer opt-out risk remains a primary risk for the CCA industry. Opt-out risk is managed through:
 Charging competitive retail generation rates, offering innovative energy programs to facilitate electrification, and reducing greenhouse gas (GHG) emissions  Engaging in ethical, transparent and honest business practices  Maintaining financial strength, including an adequate Rate Stability Reserves Fund

2.2.2 Market Risk
Market (energy price) volatility risk is the risk of losses due to the movements in power market prices, interest rates, and credit market prices. Power market price risk includes the risk of adverse price movements in energy, capacity, power basis, renewable attributes, and underlying drivers such as natural gas market prices. Interest rate and credit market price risks are considered when evaluating financing structures associated with long-term hedges or contracts. 3CE will manage market risk through the following:
 Regular measurement, including forward-looking stress tests based on multiple factors and Value-at-Risk (VaR) over multiple time horizons
 Execution of approved procurement
 Hedging and Congestion Revenue Rights strategies
Use of the Limit Structure is set forth in Section 5, below.

2.2.3 Liquidity Risk
Liquidity risk is the risk that 3CE will not be able to meet its short-term cash or financial obligations as they come due. This could occur if 3CE is unable to convert its assets into cash quickly enough to cover its immediate liabilities, or if it cannot secure financing at reasonable terms. 3CE will manage liquidity risk by maintaining sufficient cash reserves, having access to credit facilities, and implementing robust cash flow forecasting and monitoring processes to ensure it can meet its financial obligations and continue operations without disruption.

9 2.2.4 Regulatory and Legislative Risk
3CE and other CCAs are subject to an evolving legal and regulatory landscape. Additionally, CCAs are in direct competition with California’s IOUs in supplying retail electricity, and the IOUs face the risk of stranded investments in generating assets and power purchase agreements procured in the past to serve now departing CCA loads. The way such stranded costs of these legacy power supplies are allocated to departing CCA loads is subject to change based on various proceedings at the California Public Utilities Commission (CPUC). The outcome of such proceedings will directly affect the cost of power for 3CE’s customers, as well as impact the rate competitiveness of 3CE.

In addition to IOU-imposed surcharges, potential regulatory and/or legislative changes could affect the following:
 3CE’s ability to exercise local control over the manner and means of procuring power supplies to serve its customers
 Market prices
 Procurement requirements
 Cash flows
3CE will manage regulatory and legislative risks by the following activities:
 Regularly monitoring and analyzing legislative and regulatory proceedings impacting CCAs  Actively participating in, and advocating for, the interests of 3CE and its customers during regulatory and legislative proceedings

2.2.5 Volumetric Risk
Volumetric risk is the uncertainty in quantity of load served by 3CE. This leads to uncertainty in the amounts of both energy and renewable energy that 3CE must procure for its customers. Volumetric risk may be driven by factors such as attrition, weather, and behind-the-meter generation. Customer opt-out risk is explicitly modeled under this policy. Weather is the biggest short-term driver of volumetric risk. 3CE will develop load distributions that account for a wide range of weather outcomes and size positions accordingly. 3CE may set limits on open positions by tenor, as appropriate, to reduce volumetric risk.

2.2.6 Model Risk
Model risk is variance from modeled or forecasted outcomes due to fundamental deficiencies in models and/or information systems. 3CE will manage model risk by the following means:
 Validating all models on an ongoing basis for robustness, updating and/or enhancing models as needed
 Continually reviewing all model outputs
 Collaborating regularly with vendors, and exchanging information and best practices with peers bilaterally or in trainings and conferences
 Requiring all procurement transactions be recorded in a single trade capture system when that system is available

10 2.2.7 Operational Risk
Operationalrisk is variance in financial performance due to weaknesses or failures in the quality, scope, content, and/or execution of hedging, procurement, and risk management functions. Operational risk also incorporates fraudulent actions by employees or third parties, particularly due to inadequate or ineffective controls. 3CE manages operational risk through a variety of methods:
 Timely and effective reporting to the Chief Executive Officer (CEO) and the RMC  Segregation of functions
 Layered oversight
 Implementation of a compliance training program for all 3CE staff  Ongoing 3CE and consultant staff education/training and participation in industry forums  Annual internal audits to test compliance with the ERMP

2.2.8 Counterparty & Generalized Credit Risk
Counterparty risk is the risk that a counterparty will fail to perform or adequately remedy its obligations in accordance with contractual and transactional terms. Generalized credit risk is the risk of a generalized reduction in credit to a sector, a set of counterparties, or a specific counterparty that results in an increase in counterparty risk. 3CE will monitor counterparty risk based on a variety of metrics and analyses, including but not limited to an in-depth review of counterparty financials when not rated by a credit rating agency, exposure by credit rating, exposure by tenor and product type.

11 SECTION 3: ORGANIZATIONAL STRUCTURE AND RESPONSIBILITIES

3.1 Risk Management Organizational Structure
3CE risk management is organizationally structured to ensure effective segregation of duties and multiple layers of oversight using a waterfall approach. Risk approval limits are contained in Section 9, the Risk Management Delegation of Financial Authority (DOFA).

The 3CE Operations Board of Directors (Operations Board) is responsible for approving this ERMP. It reviews and approves this policy and approves risk exposures above those delegated to the Chief Executive Officer (CEO) or Risk Management Committee (RMC) in the DOFA.

The RMC is responsible for overseeing strategic compliance with this policy and approving risk exposures above those delegated to the CEO.

The Front Office is responsible for the energy short-term trading function and long-term negotiations of power supply contracts, mindful of ERMP limits.

The Middle Office is responsible for ensuring compliance with this ERMP and monthly reporting of risk exposure to the RMC. This segregates the monitoring and trading functions, ensures adherence to risk limits and provides an important check and balance.

The Back Office is responsible for processing payments, ensuring adherence to contract terms and providing appropriate reporting to regulatory agencies.

3.2 Risk Management Committee
The CEO shall establish the RMC, set the agenda, and serve as its Chair. The RMC consists of the following voting members:
 Chief Executive Officer
 Up to five (5) members of 3CE’s Policy and/or Operations Board of Directors, selected by the CEO
 Chief Financial Officer
 Chief Operating Officer
 Chief Communications Officer
The RMC is responsible for overseeing strategic compliance with this ERMP and approving major risk exposures above those delegated to the CEO. This includes ensuring procurements and hedging are consistent with 3CE’s strategic goals.

Specifically, the RMC maintains the authority and responsibility to:
 Ensure that procurements are consistent with this ERMP and hedging plans based on 3CE’s

12 financial objectives and situation
 Approve procurements and risk exposures above those delegated to the CEO and up to the limits specified in the DOFA, based on the strategic goals of this ERMP and 3CE’s financial situation
 Understand and approve the limits, metrics, and product types necessary to ensure compliance with this ERMP
 Review risk management reports as described in this ERMP  Review actual and projected risks and financial outcomes and review summaries of violations of this ERMP
 Refer to the Operations Board those exposures and risks above those delegated to the RMC in the DOFA

3.3 Segregation of Duties
3CE shall maintain a segregation of duties, also referred to as "separation of function,” to help manage and control the risks outlined in this ERMP. Individuals responsible for legally binding 3CE to a transaction will also not perform confirmation or settlement functions without supplemental, transparent, and auditable controls. 3CE will leverage the organizational structure of the Scheduling Coordinator’s Middle and Back offices to help maintain a segregation of duties. The Front, Middle and Back Office responsibilities for 3CE are described below.

3.3.1 Front Office
The Front Office is headed by the Director of Power Supply Resources. The Front Office is responsible for the procurement and hedging activities necessary to manage 3CE’s wholesale power market positions and obligations. Specific responsibilities include:
 Developing long-term procurement strategies to reliably meet 3CE’s load-serving obligation using a least-cost best-fit approach
 Developing annual, quarterly, and monthly hedge plans to prudently meet 3CE’s load-serving obligation using a mix of market transactions and 3CE’s power assets  Optimizing 3CE’s load-supply balance and asset management strategies to prudently maximize value for 3CE customers while adhering to all risk management processes and limits  Overseeing and directing scheduling of load and resources into the CAISO  Developing and using fundamental and probabilistic analysis – such as power market supply-demand balances and transmission outages – to guide optimization, procurement, and hedging decisions
 Accurately recording all transactions in the System of Record  Accurately tracking open forward positions and hedge performance across tenorsfor all power products (energy, renewable energy, carbon-free energy and resource adequacy capacity)  Maintaining forward prices for all illiquid power products (renewable energy credits, carbon-free energy and resource adequacy capacity) in the System of Record  Executing transactions and negotiating or amending contracts as needed to meet the above

13 goals in accordance with the limits set out in the DOFA. Restructuring previously approved transactions and contracts as needed in accordance with the DOFA limitations  Managing and facilitating the transaction execution process for power supply transactions through coordination of the following activities:
a. Notifying Front Office personnel of any anticipated unique physical delivery or scheduling issues
b. Working with Middle Office personnel and legal counsel to establish a contract, evaluate counterparty creditworthiness and secure additional credit from the counterparty, if necessary
c. Working with Middle Office, as needed, to perform an analysis of the potential transaction to evaluate the effects on 3CE’s portfolio risks d. Notifying Back Office of terms and conditions affecting settlement to ensure that the necessary settlement procedures are in place

3.3.2 Middle Office
The Middle Office functions are the responsibility of the Chief Financial Officer. The Middle Office is responsible for implementing, administering, and monitoring compliance with this ERMP. Specific responsibilities include:
 Developing market and transaction analytics that inform risk analyses of 3CE’s hedging and procurement activities, providing Front Office with independent views as needed  Developing metrics and risk management processes for the risks identified in the Risk Catalog in this ERMP
 Designing and setting hedging and procurement limits, including but not limited to product types, tenors, delivery points, counterparties, and markets  Monitoring risk exposures and policy compliance on an ongoing basis, with monthly reporting to the RMC
 Validating all positions, prices, and forecasts in the System of Record  Developing limits with exchanges, brokers, and trading venues  Analyzing risk of the hedging and procurement plans developed by the Front Office  Assisting consultants in developing and maintaining demand forecasts  Developing internal estimates of forward prices used in valuation, pricing and monitoring where credible liquid data is not available
 Assisting in expert valuation of all 3CE positions and contracts  Supporting settlement validation, as necessary
 Reporting limit violations to the RMC
 Validating the net forward power positions of 3CE
 Assist Back Office in calculating Counterparty Credit Exposure

14 3.3.3 Back Office
The Back Office is responsible for the administrative activities necessary to execute and settle transactions and contracts and to support the Middle Office where necessary to monitor compliance with this ERMP.

Specific responsibilities include:
 Confirming all transaction details (physical and financial) and reconciling differences with the trading counterparties
 Reviewing transaction confirmations for adherence to approved limits  Validating trade entry and flow through the System of Record  Validating and reconciling physical and financial transaction flows  Settling trades and calculating revenues and profit & loss  Providing settlement, credit, and other data as needed to the Middle Office and Finance to support monitoring of risk exposures and budget processes  Validating and promptly paying of energy related invoices payable by 3CE and resolving disputes with counterparties
 Generating and promptly collecting energy related invoices payable by counterparties

15 SECTION 4: BUSINESS PRACTICES

4.1 General Conduct
All personnel, including Members of the Operation and Policy Board of Directors, staff, and agents, (collectively referred to “3CE Representatives”) adhere to standards of integrity, ethics, conflicts of interest, compliance with statutory law and regulations and with applicable 3CE standards of personal conduct while employed by, contracted by, or affiliated with 3CE.

4.2 Hedging & Trading Activities; Prohibition on Speculation 3CE contracts and trades in energy markets to hedge positions, reduce risk, and, in compliance with this ERMP, prudently optimize the value of its portfolio of assets and market positions. Speculative trading is explicitly prohibited under this ERMP. Examples of speculative trading include trading a commodity for which 3CE does not have an underlying position or risk, trading a product based solely on personal judgement about future market direction, taking positions in volumes that deviate significantly from 3CE’s underlying need, etc. Should a question arise about speculative trading activities, 3CE’s Middle Office will make an initial finding based on an analysis of the situation and present a written report to the RMC. The RMC will make a final determination based on the situation.

4.3 Trading for Personal Accounts
All 3CE staff and agents are prohibited from trading the power and environmental products traded by 3CE for personal accounts.

4.4 Conflict of Interest
3CE staff are expected to meet the highest standards for ethical conduct, beyond just the specific matters discussed in this section.
3CE staff responsible for negotiating, reviewing, and/or approving hedging activities and procurements are obligated to provide written notice to 3CE of any real or potential conflict of interest in the matter.

An example of such a conflict of interest may be negotiating with a counterparty while seeking employment for oneself or a relative with that counterparty. 3CE staff are prohibited from trading on information gained during hedging and procurement activities.

An example of such an activity would be a 3CE employee directly or indirectly purchasing stock in a developer prior to the announcement of 3CE awarding that developer a significant contract. Purchases of pooled vehicles such as broadly diversified mutual funds and ETFs are exempted from this ERMP. 3CE Front Office staff are expected to seek best execution and least-cost best-fit product attributes from counterparties and intermediaries. Steering trades and contracts to counterparties based on potential financial gain or personal relationships is prohibited.

16 Additionally, Conflicts of Interest shall be identified and defined as set forth in the 3CE Conflict of Interest Code, as amended from time to time by the Policy Board, which incorporates the Political Reform Act requirements for all employees advising 3CE.

If there is any doubt as to whether a prohibited condition exists, then it is the Representative’s responsibility to discuss the possible prohibited condition with 3CE General Counsel. Employees may seek an advisory position from the California Fair Political Practices Commission.

4.5 Adherence to Statutory Requirements
Compliance is required with rules promulgated by the state of California, California Public Utilities Commission (CPUC), California Energy Commission (CEC), Federal Energy Regulatory Commission (FERC), Commodity Futures Trading Commission (CFTC), and other regulatory agencies.

Congress, the FERC and the CFTC have enacted laws, regulations and rules that prohibit, among other things, any action or course of conduct that actually or potentially operates as a fraud or deceit upon any person in connection with the purchase or sale of electric energy or transmission services. These laws also prohibit any person or entity from making any untrue statement of fact or omitting to state a material fact where the omission would make a statement misleading. Violation of these laws can lead to both civil and criminal actions against the individual involved, as well as 3CE. This ERMP is intended to comply with these laws, regulations, and rules and to avoid improper conduct on the part of anyone employed by 3CE. These procedures may be modified from time to time due to legal requirements, auditor recommendations, RMC requests and other considerations.

In the event of an investigation or inquiry by a regulatory agency, 3CE may provide legal counsel to employees. However, 3CE, with the consent of the Operations Board, will not appoint legal counsel to an employee if 3CE determines that representation of the employee will create an actual conflict between the employee and 3CE, or that the employee was not acting in good faith within the scope of employment.

4.6 Authorized Products, Markets & Terms
Transactions are conducted bilaterally, using standard contracts under previously executed counterparty enabling agreements such as the Edison Electric Institute’s Master Power Purchase & Sale Agreement (EEI) or Western Systems Power Pool’s Agreement (WSPP), or through exchanges such as the InterContinental Exchange (ICE). 3CE’s CEO, or their designee, must authorize all counterparty enabling agreements as well as all individual transactions.

New products, tenors, markets, delivery points, and transaction types can be authorized by the RMC.

When seeking such approval, a New Product Approval Form, as shown in Appendix C, should be drafted describing all significant elements of the proposed product. This should include, at a minimum:
 A description of the benefit to 3CE, such as decreasing costs, managing volatility etc.  The role of the new product in 3CE’s overall portfolio and risk management strategies

17  Risk analysis that identifies the specific risks mitigated by the new product and illustrates its application
 Transaction process, initial risk limits and settlement process  Proposed valuation methodology (including pricing model, where appropriate)  Proposed accounting methodology
3CE’s CEO or their designee is responsible for requesting the RMC’s approval. If approved, Appendix A to the Policy will be updated to reflect the new transaction type

4.7 System of Record
3CE will maintain a secure set of records for all transactions executed in association with 3CE procurement activities. 3CE’s Technology and Data & Analytics group supports the security, integrity, and recoverability of the System of Record. For data recoverability, transaction data stored in the System of Record is replicated daily to ensure data redundancy and is backed-up via cloud-based applications.

The records will be maintained in US dollars and transactions will be separately recorded and categorized by type of transaction. This system of record shall be auditable and audited as appropriate.

4.8 Transaction Valuation
Transaction valuation and reporting of positions shall be based on objective, market-observed prices.

Whenever possible, mark-to-market valuations should be based on independent, publicly available market information and data sources. The Middle Office will be responsible for independently validating and reporting marks and valuations.

4.9 Policy Compliance
The Middle Office will provide a monthly report to the RMC monitoring compliance with the limits established by the ERMP.

18 SECTION 5: TOLERANCES

5.1 Hedging Tolerances
Hedging tolerances for energy, renewable attributes, capacity (resource adequacy) and carbon-free energy are shown below. From time to time, the Middle Office, in response to market conditions, may recommend adjustments to these ranges.

While 3CE is generally a purchaser of energy and related products, there are instances in which staff might wish to rebalance the portfolio through the sale of contracts or other market products, as appropriate, in order to realign exposures with the agency’s risk tolerances and policy objectives. All such actions will be conducted in accordance with this Policy and the applicable Delegation of Authority.

5.1.1 Energy Procurement Tolerances
Fixed Price Energy purchases provide for suppliers to deliver energy – for which 3CE will receive energy market revenues – to 3CE at a fixed price. They are used to manage the electricity commodity price risk that 3CE faces as a Load Serving Entity. Specific to 3CE ‘s customers, Fixed Price Energy hedges are used to provide cost certainty and rate stability.
3CE predominantly employs Fixed Price Block Energy contracts, which provide for suppliers to deliver a predetermined volume of energy at a constant delivery rate. As 3CE enters into long-term, fixed price contracts for renewable and/or carbon-free energy, these will likewise hedge 3CE’s market risk and, subsequently, reduce the required volume of Fixed Price Block Energy purchases.

When assessing its requirements for Fixed Price Energy, 3CE will use an econometric model to forecast hourly energy requirements and monthly peak demand by customer load class. The model will use historical data to estimate relationships between energy consumption and economic, demographic and/or weather variables. The model will be refined through time as additional load and other data is acquired.
3CE will observe the following schedule when hedging its Fixed Price Energy Requirements. The Minimum and Maximum hedge % represent the Fixed Price Energy planned or under contract divided by forecasted wholesale load.

Quarter
Minimum
Hedge %
Maximum
Hedge %
Prompt Q
(PQ) 85% 110%
PQ + 1 80% 110%

19 PQ + 2 74% 110%
PQ + 3 69% 110%
PQ + 4 63% 105%
PQ + 5 58% 99%
PQ + 6 52% 93%
PQ + 7 47% 87%
PQ + 8 41% 82%
PQ + 9 36% 76%
PQ + 10 -
15 30% 70%
Notwithstanding the maximum hedge levels shown in the above table, there shall be no maximum hedge level in quarters in which 3CE only owns long-term power purchase agreements and energy storage agreements.

Energy hedging compliance will be measured within 5 days prior to the first day of each quarter (e.g., on a date between September 26th and September 30th, 2024, 3CE will have hedged 85 to 110 percent of its projected energy requirements for Q4 2024 and 80 to 110 percent of requirements for Q1 2025).

The minimum hedge level will be achieved by implementing a time-driven programmatic strategy.

Time-driven programmatic hedges are executed at a predetermined rate pursuant to a time schedule and without regard for market conditions. The purpose of these hedging transactions is to achieve a reduction in variability in power supply costs by gradually increasing the amount of energy hedged as the actual date of consumption approaches. Time-driven strategies avoid the inherent impossibility of trying to consistently and accurately “time the market” to purchase energy at least cost when making hedging decisions. Additionally, a load serving entity the size of 3CE needs to spread its procurement efforts over time to effectively manage the potential negative price impacts of procuring a large volume of energy, over a short period of time, in an illiquid market.

Hedging decisions to reach targets between the minimum and maximum hedge levels will be based on price-driven or opportunistic strategies. The purpose of price-driven or opportunistic strategies is to capitalize on market opportunities when conditions are favorable. 3CE will base its decision to execute opportunistic hedges on the anticipated impact to projected power supply costs and the resulting reduction in risk.

Opportunistic hedges may be executed when energy price levels are favorable to lowering the cost of power relative to established program goals and financial projections; alternatively, opportunistic

20 hedges can be executed in adverse market conditions relative to financial goals in order to reduce the potential negative impact of continued upward trending commodity prices relative to established goals.

In executing this energy risk hedging strategy, Fixed-Price Energy hedges may be modified, repositioned or unwound for the purpose of maintaining hedge coverage that matches changes in forecast electric load or supply. This includes the ability of 3CE to use liquid market products to hedge average loads over a defined time period and then later modify its hedges to more precisely match load.

5.1.2 Renewable Energy Procurement Tolerances
In order to cost-effectively meet its GHG-reduction and renewable energy goals, 3CE intends to meet a growing share of its energy supply requirements with renewable energy, a large portion of which will be Product Content Category 1 (PCC1) renewable energy. PCC1 renewable energy is sourced from a renewable generator that is either directly interconnected to the California Independent System Operator (CAISO) or another California Balancing Authority or directly scheduled into CAISO without use of substitute energy. 3CE may diversify its renewable energy portfolio further by incorporating Portfolio Content Category 2 (PCC2) renewable energy purchases. PCC2 renewable energy is sourced from renewable generators located outside the state of California, where that generation is “firmed and shaped” for delivery into California. PCC2 purchases are typically less expensive and shorter in term than PCC1, so they provide a cost-effective and flexible method of augmenting 3CE’s renewable energy purchases to meet renewable portfolio content commitments to customers. However, not all PCC2 renewable energy is emissions-free; therefore, 3CE must assess the value of PCC2s against its respective emissions intensity. In addition, RPS compliance rules set minimum requirements for PCC1 and PCC2 as a percentage of the total RPS compliance portfolio, which 3CE will abide by in its procurement of both products.

In order to manage price risk of long-term renewable energy, and to allow 3CE to prudently and methodically build a portfolio of long-term assets, 3CE intends to meet its renewable energy targets with a blend of short- and long-term contracts. 3CE intends to fully comply with long-term contracting requirements mandated by SB 100; therefore, executed and planned long-term renewable contracts will be reflected in 3CE’s renewable energy positions.
3CE shall observe the following schedule while hedging its SB 100 annual minimum renewable energy requirements. The minimum hedge percentages specified shall be measured during the final five days of each calendar year, based on the applicable renewable energy vintage for each compliance year.

21 Measurement
Year (as of final
five days)
2025 Vintage
Minimum
Hedge (%)
2026 Vintage
Minimum
Hedge (%)
2027+ Vintage
Minimum Hedge
(%)
2025 100 90 90
2026 100 100 90
2027 — 100 100 (2027 Vintage)
2028 — — 100 (2028 Vintage)
2029 — — 100 (2029 Vintage)
2030 — — 100 (2030 Vintage)

5.1.3 Capacity Procurement Tolerances
As a Load-Serving Entity (LSE) in California, 3CE is required to demonstrate both annually and monthly that it has secured sufficient energy capacity to provide for its share of California’s energy load; this capacity is referred to as resource adequacy (RA).

RA is typically transacted via contracts that vary in length, and it is currently bought and sold via a bilateral market. This market provides cost-effective contracting opportunities, but also proves at times to be fragmented and volatile. It is the goal of 3CE to meet all RA requirements, including local, flexible, and system requirements.
3CE will observe the following schedule when hedging its year-ahead RA requirements. The hedge schedule shall be measured for the system RA product by month that 3CE is required to procure within 5 days prior to December 1 of each year for the Prompt Calendar Year and the four subsequent calendar years.

Time Period Minimum Hedge %
(applicable to the shortest hour
of each month)
Maximum Hedge %
(applicable to shortest hour of
peak month only)2
Prompt Calendar Year 90 100
PY + 1 50 95

2 Due to the variable nature of 3CE’s monthly RA requirements, non-peak months may exceed the applicable Maximum Hedge %.

22 PY + 2 35 90
PY + 3 35 80
PY + 4 35 80
Month-ahead system and flexible RA requirements will be met with the required monthly CPUC filing.

5.1.4 Carbon-Free Energy Tolerances
3CE may have the opportunity to receive free carbon-free energy allocations from PG&E and SCE at zero cost. Hedging activity should consider these allocations and expected allocations should be included in the hedging percentages.
3CE will observe the following schedule when hedging its carbon-free renewable energy requirements.

This hedge schedule shall be measured within 5 days prior to the first day of each quarter for the Current Calendar Year, and within 5 days prior to December 1 of each year for the following ten Calendar Years.

Time Period Minimum Hedge % Maximum Hedge %
Current Calendar Year 85 110*
Prompt Calendar Year 75 110*
PY + 1 50 110
PY + 2 25 100
PY + 3 0 75
PY + 4 - 9 0 75
* Maximum hedge percentages allow for a planning margin to accommodate volumetric uncertainty associated with electric consumption and generation In setting the above targets, it is important to note that the purchase of carbon-free energy is a voluntary requirement set by the 3CE Board to exceed states’ GHG emissions goals. In determining the total volume of carbon-free energy to be hedged, the 3CE Board may elect to increase or reduce the total quantity of carbon-free energy included in 3CE’s portfolio as it seeks to balance multiple program objectives, including financial goals such as targets for financial reserves and retail rates.

5.1.5 Congestion Revenue Rights (CRRs)
As a CAISO market participant, 3CE has congestion risk associated with serving its customer load. 3CE

23 manages congestion risks by preferring day ahead scheduling of energy delivered at NP-15 and SP-15, and by resource assessment and selection consistent with this ERMP. Once energy is procured, 3CE manages congestion risk through the prudent management of CRRs, which are financial instruments used to hedge against transmission congestion costs encountered in the CAISO day-ahead market. The RMC is responsible for overseeing the management of CRRs and CRR trading. The CRR portfolio will be managed by 3CE 's Front Office with support from 3CE’s Scheduling Coordinator. CRRs are transacted to effectively manage portfolio congestion risk, through hedging and value maximization. Trading of CRRs for speculative purposes is not permitted.

CRR position restriction: 3CE shall not use the annual or monthly CRR auctions to do any of the following:
 Increase CRR holdings on paths not related to 3CE’s generation, storage or inter-scheduler trades (ISTs)3
 Increase CRR holdings above expected generation, discharge or IST volumes on paths related to 3CE’s generation, storage or ISTs

5.2 Monitoring, Reporting and Instances of Exceeding Risk Limits The Middle Office is responsible for monitoring, and reporting compliance with, all limits within this ERMP. If a limit or control is violated, the Middle Office will notify the RMC. The RMC will discuss the cause and potential remediation of the exceedance to determine next steps for curing the exceedance.

3 Inter-scheduler trades source at NP-15. In addition to purchasing CRRs at NP-15, 3CE may additionally purchase CRRs on paths that have been found to be good proxies for NP-15.

24 SECTION 6: CREDIT POLICY
Counterparty and generalized credit risk are significant risks to 3CE’s financial operations. The Middle Office will conduct a thorough analysis of all candidate counterparties prior to approving them to transact. This analysis will include but not be limited to analyzing the proposed counterparty’s financial statements (if unrated), credit rating, liquidity, hedge levels, market sensitivity, and business operations. The Middle Office will determine whether to extend an unsecured or secured credit line to the candidate counterparty, as appropriate. The maximum unsecured credit line that can be extended to any counterparty is $50 Million.

In addition to individual counterparty limits, the Middle Office will set limits by credit rating, tenor, product, and, where appropriate, transaction type and delivery type. For example, it may set an overall limit of $50 million for counterparties rated BB+ that supersedes the BB+ counterparties’ individual credit approvals of $100 million. This will limit the concentration of credit risk.

Counterparty credit health and generalized credit conditions will be monitored on an ongoing basis.

Individual counterparty limits or aggregate credit limits by tenor/product/credit rating may be adjusted up or down to reflect current conditions. Counterparties who exceed limits must promptly post enough collateral to come into compliance or risk having their positions liquidated.

25 SECTION 7: POSITION TRACKING AND MANAGEMENT REPORTING Minimum reporting requirements are shown below. The reports outlined below will be made available to RMC members:
 Monthly Financial Model Forecast
Latest projected financial performance, marked to current market prices, and shown relative to financial goals
 Monthly Net Position Report
Latest forward net position reports of all product classes  Monthly Counterparty Credit Exposure
Credit exposures for transactions executed by 3CE
 Monthly Risk Analysis
To include a stress test of financial forecast relative to financial goals

26 SECTION 8: POLICY REVISION PROCESS
3CE’s Energy Risk Management Policy (ERMP) will evolve over time as market and business factors change. At least on an annual basis, the RMC will review the ERMP and associated procedures to determine if they should be amended, supplemented, or updated to account for changing business and/or regulatory requirements. If an amendment is warranted, the ERMP amendment will be submitted to the 3CE Operations Board for approval. Changes to appendices to this ERMP may be approved by the RMC.

8.1 Acknowledgement of Policy
Any 3CE employee participating in any activity or transaction within the scope of the ERMP shall sign on an annual basis or upon any revision, a statement approved by the RMC that such employee:
 Read 3CE’s ERMP
 Understands the terms of said ERMP
 Will comply with said ERMP
 Understands that any violation of said ERMP shall be subject to employee discipline up to and including termination of employment

8.2 Policy Interpretations
Questions about the interpretation of any matters of this ERMP should be referred to the CEO. All legal matters stemming from this ERMP will be referred to General Counsel.

27 SECTION 9: DELEGATION OF FINANCIAL AUTHORITY
The Policy and Operations Boards of Directors (Boards) explicitly delegates approval of transactions to the CEO and the RMC as outlined in the following table:

Position Maturity Limit Term Limit Value Limit ($)1
Risk Management Committee 96 Months 60 Months 110,000,000 Chief Executive Officer 96 Months 60 Months 65,000,000
1 “Value Limit” is the total notional value of the transaction, inclusive of any related procurement fees.

These delegated authorities may be further delegated and used to set hedging and procurement limits necessary to manage 3CE’s portfolio. For example, the CEO could authorize the Front Office to trade up to the CEO’s authority limits in approved products.

Additionally, to adapt to changing market conditions and to facilitate the daily operations of 3CE, the Boards have delegated authority to the CEO (or designee) to execute administrative amendments to duly approved transactions where such amendments do not exceed the CEO’s delegated authority as set forth above (for clarity, amendments exceeding Maturity, Term or Value limits shall require Operations Board approval) and further reduces 3CE’s risk in furtherance of this ERMP. Such administrative amendments must be reported during the next RMC meeting and Operations Board meeting.

These authorities will be applied to wholesale power activity executed outside of the California Independent System Operator (“CAISO”) markets. These limits provide 3CE needed authorities to manage risks as they arise. Transactions falling outside the delegations above require Board approval prior to execution. Activity with CAISO is excluded from this table due to the nature of the market, where prices for activity may not be known until after transactions are committed.

All procurement executed under the delegation above must align with the 3CE’s underlying risk exposure (locational, volume and temporal) that is being hedged consistent with the approved Procurement Strategy.

The point of delivery for all products must be at a location on the CAISO transmission grid.

28 Appendix A: AUTHORIZED TRANSACTION TYPES, REGIONS, AND MARKETS All transaction types listed below must be executed within the limits set forth in this ERMP.

Over the Counter Products
 CAISO Market Products
o Day-ahead and Real-time Energy
o Congestion Revenue Rights
o Convergence bids
o Inter Scheduling Coordinator Transactions
o Tagging into and out of CAISO
 Physical Power Products
o Power
o Physical Over-the-counter Options
o Physical Resource Adequacy Capacity
 Import Capability Rights
 Physical Transmission Products
o Physical WECC Transmission
 Physical Environmental Products
o Renewable Energy Credits
o Specified Source Power
o Carbon Allowances and Obligations
 Financial Power Products
o Power
o Financial Over-the-counter Options
 Physical Natural Gas Products
o Firm or interruptible natural gas supply contracts
o Swing supply contracts (daily or monthly flexibility) o Physical delivery at trading hubs (e.g., SoCal Border, SoCal Citygate, PG&E Citygate, Malin, etc.)
 Financial Natural Gas Products
o Fixed-for-floating swaps (e.g., Henry Hub, SoCal Citygate, PG&E Citygate) o Basis swaps (e.g., Henry Hub vs. SoCal Citygate, Henry Hub vs. PG&E Citygate) o Financial futures and forwards (e.g., NYMEX Henry Hub)  Broker Fees

29 Appendix B: NEW TRANSACTION APPROVAL FORM
New or Non-Standard Transaction Approval Form
Prepared By:

Date:

New or Non-Standard Transaction Name:

Business Rationale and Risk Assessment:
 A description of the benefit to 3CE, such as decreasing costs, managing volatility etc.  The role of the new product in 3CE’s overall portfolio and risk management strategies  Middle Office risk analysis that identifies the specific risks mitigated by the new product and illustrates its application
 Transaction process, initial risk limits and settlement process  An assessment of the legal, tax, and regulatory aspects of the product  Proposed valuation methodology (including pricing model, where appropriate)  Proposed reporting requirements, including any changes to existing procedures and system requirements necessary to support the new transaction type  Proposed accounting methodology
Reviewed by:

30 Appendix C: DEFINITIONS
Back Office: That part of a trading organization which handles transaction accounting, confirmations, management reporting, contract administration and working capital management, which reports to the Chief Operating Officer.

Bilateral Transaction: Any physical or financial transaction between two counterparties, neither of whom is an Exchange or market entity such as CAISO.

Cash Flow at Risk: A measure of the potential shortfall in cash flow from a specified level during a specified period of time at a specified confidence level.

CAISO: California Independent System Operator. CAISO operates a California bulk power transmission grid, administers the State’s wholesale electricity markets, and provides reliability planning and generation dispatch.

California Energy Commission (CEC): CEC is the primary energy policy and planning agency for California.

California Fair Political Practices Commission (FPPC): FPPC is a five-member independent, non-partisan commission that has primary responsibility for the impartial and effective administration of the Political Reform Act.

California Public Utilities Commission (CPUC): CPUC is a regulatory agency that regulates privately owned public utilities in the state of California, including electric power, telecommunications, natural gas and water companies.

Community Choice Aggregator (CCA): CCAs allow local government agencies such as cities and/or counties to purchase and/or develop generation supplies on behalf of their residents, businesses, and Chief Operating Officer Date
Chief Financial Officer Date
General Counsel Date
Chief Executive Officer Date

31 municipal accounts.

Commodity Futures Trading Commission (CFTC): The CFTC is a U.S. federal agency that is responsible for regulating commodity futures and swap markets. It goals include the promotion of competitive and efficient futures markets and the protection of investors against manipulation, abusive trade practices and fraud.

Clearing: Clearing is the process of reconciling purchases and sales of a commodity, as well as the direct transfer of funds from one financial institution to another. The process validates the availability of funds, records the transfer, and in the case of financial securities, ensure the delivery to the buyer.

Commodity: A basic good used in commerce that is interchangeable with other commodities of the same type. Commodities aremost often used asinputsin the production of other goods orservices. The quality of a given commodity may differ slightly, but it is essentially uniform across producers. When they are traded on an exchange, commoditiesmust alsomeetspecifiedminimum standards, also known as a basis grade.

Confirmation Letter: A letter agreement between two counterparties that details the specific commercial terms (e.g., price, quantity and point of delivery) of a transaction.

Congestion Revenue Right: A point-to-point financial instrument in the Day-Ahead Energy Market that entitles the holder to receive compensation for or requires the holder to pay certain congestion related transmission charges that arise when the transmission system is congested.

Counterparty Credit Risk: The risk of financial loss resulting from a counterparty to a transaction failing to fulfill its obligations.

Counterparty Credit Exposure: This measures the known exposures and is represented by the sum of both (a)Realized exposure and (b) Forward exposure, as those terms are defined below:

Realized exposure: payable or receivable amount owed between counterparties, is a measurement of cash flow for billed and unbilled transactions.

Forward exposure: measure of current unrealized exposure and includes the measure of a counterparty’s incentive to fulfill contractual obligations. Forward exposure measures the risk associated with having a payment default or the need to replace a transaction in the event of delivery default.

Edison Electric Institute (EEI): EEI is an association that represents all U.S. investor-owned electric companies.

Day-ahead Market: The short-term forward market for efficiently allocating transmission capacity and facilitating purchases and sales of energy and scheduled bilateral transactions; conducted by CAISO prior to the operating day.

Delivery point: the point at which a commodity will be delivered and received.

Federal Energy Regulatory Commission (FERC): FERC is a federal agency that regulates the interstate transmission of electricity, natural gas, and oil. FERC also reviews proposals to build liquefied natural gas terminals, interstate natural gas pipelines, as well as licenses hydroelectric generation projects.

Front Office: That part of a trading organization which solicits customer business, services existing customers, executes trades and ensures the physical delivery of commodities, which reports to the Chief Operating Officer.

Hedging products: Hedging products means capacity, energy, renewable energy credits or other products related to a specific transaction.

32 Hedging Transaction: A transaction designed to reduce the financial exposure of a specific outstanding position or portfolio; “fully hedged” equates to complete elimination of the targeted risk and “partially hedged” implies a risk reduction of less than 100%.

InterContinental Exchange (ICE): ICE s an American company formed in 2000 that operates global financial exchanges, clearing houses and provides mortgage technology, data and listing services.

Investor-Owned Utility (IOU): An IOU is a business organization providing electrical and/or natural gas services to both retail and wholesale consumers and is managed as a private enterprise. Pacific Gas & Electric Company (PG&E) and Southern California Edison (SCE) are examples of IOUs.

Middle Office: That part of a trading organization that measures and reports on market risks, develops risk management policies and monitors compliance with those policies, manages credit, and keeps management and the Board informed on risk managementissues, which reports to the Chief Financial Officer.

Speculation: Speculation is the act of trading an asset with the expectation of realizing financial gain resulting from a change in price in the asset being transacted.

Value-at-Risk (VaR): VaR is a risk tolerance metric that quantifies the extent of possible financial losses within a firm, portfolio, or position over a specific time frame.

Western Systems Power Pool (WSPP): WSPP is an organization of electrical wholesale market entities that have developed and utilize a standardized agreement (WSPP Agreement) to execute trading opportunities, allowing WSPP members to manage power delivery and price risk.

33

RESOLUTION NO. OB-2025-05

A RESOLUTION OF THE CENTRAL COAST COMMUNITY ENERGY OPERATIONS BOARD

OF DIRECTORS APPROVING AMENDMENTS TO THE ENERGY RISK MANAGEMENT POLICY
WHEREAS, Central Coast Community Energy (3CE) is a Joint Powers Authority (JPA) established and operated pursuant to California Government Code sections 6500 et seq. to study, promote, develop, conduct, operate, and manage energy programs in the California Central Coast region of Santa Cruz, Monterey, San Benito, Santa Barbara, and San Luis Obispo Counties; and
WHEREAS, 3CE’s Energy Risk Management Policy (“ERM” Policy) was originally adopted by the Policy Board of Directors on March 7, 2018; and
WHEREAS, the ERM Policy requires that it be reviewed at least annually to ensure it evolves to address potential market, regulatory, or business changes that impact 3CE’s procurement of energy and energy related products; and
WHEREAS, the EMR Policy provides that following such review by the Risk Management Committee, any necessary amendment(s) to the ERM Policy will be considered and approved by the Operations Board.

WHEREAS, the ERM Policy was revised and amended on September 5, 2018, November 4, 2020, June 30, 2022, and October 9, 2024, by the Operations Board of Directors; and WHEREAS, the Risk Management Committee reviewed and considered the amendments set forth in herein at its September 25, 2025 meeting and unanimously recommended they be presented to the Operations Board for consideration; and,

NOW, THEREFORE, THE CENTRAL COAST COMMUNITY ENERGY OPERATIONS BOARD OF DIRECTORS DOES HEREBY RESOLVE, DETERMINE, AND ORDER AS FOLLOWS:

1. The amended Central Coast Community Energy, Energy Risk Management Policy, which is attached hereto as Attachment A, is hereby approved.

2. The Resolution shall take effect immediately upon adoption.

PASSED AND ADOPTED this 12th Day of November 2025, by the following vote:

AYES:

NOES:

ABSENT:
__________________________________
Chair, Matt Huffaker

Attest:
_________________________________
Board Clerk, Heather Vowell

Staff Report Item 8
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Thomas White, Accountant
SUBJECT: Investment Performance Report for the period of October 1, 2024, through September 30, 2025
DATE: November 12, 2025
RECOMMENDATION:
3CE investment performance report for the period of October 1, 2024, through September 30, 2025.

BACKGROUND:

As of September 30, 2025, Central Coast Community Energy held $222.9 million across its operating and investment accounts. The agency’s investment strategy remains conservative and compliant with the Investment Policy and the California Government Code, prioritizing liquidity, preservation of capital, and a passive investment approach. The portfolio's structure is designed to support day-to-day operating needs, meet collateral calls, and maintain reserves for strategic and rate stabilization purposes.

In the fourth quarter, 3CE established a new account with West Coast Community Bank to further diversify its financial holdings. The selection of a local banking partner within 3CE’s service area supports community investment while providing a secure vehicle to hold funds designated for capital outlay from the Capital Infrastructure Reserve.

DISCUSSION/ANALYSIS:
3CE ended the quarter on September 30, 2025, with investment holdings that aligned with the Investment Policy and a strategy of maintaining sufficient cash to meet operating costs, including counterparty collateral calls. The strategy consists of holding three different classes of funds: cash to meet ongoing operating costs, liquidity reserves to meet collateral calls, capital acquisition, and unforeseen costs, and short-term investments to meet reserves, including the strategic reserve and

energy rate stabilization funds. As of September 30, 2025, 3CE held $222.9 million in operating and investment accounts. The table below lists the cash and investment balances by account type.

Cash and Investment Mix Holdings by Institution
Account Type Institution Balance Investment Mix
Operating
River City Bank $76,322,375
Cash (sweep) - $69.0M
money market - $0.3M
cash (operating) - $4.0M
letters of credit - $2.9M
Chase
$11,451,091 cash (held for collateral)
West Coast Community Bank $4,554,975 money market
Investment
Schwab $64,631,557
Treasuries - $60.7M
cash (sweep) - $3.5M
money market - $0.5M
Fidelity $65,928,781 Treasuries - $64.5M
money market - $1.4M
Total $222,888,780
3CE employs a conservative, passive investment strategy in which fixed-income securities—primarily U.S. Treasury notes and bills—are held to maturity, allowing the agency to realize coupon income and discounts over time. As of September 30, 2025, 3CE managed $130.7 million in investments across its Schwab and Fidelity brokerage accounts. During the fourth quarter, Treasury yields averaged between

3.50% and 4.38%. Short-term Treasuries with maturities under one year represented approximately 92% of total holdings, while two longer-term Treasuries, each valued at $5.0 million, mature in the second and third quarters of 2027. All investments are rated high-grade or better, consistent with 3CE’s prudent investment policy.
3CE’s investment mix aligns with the Investment Policy and California Government Code. As of September 30, 2025, 3CE held $90.9 million in cash and cash equivalents, $126.6 million in U.S.

Treasuries, and $5.4 million in money market funds. Aside from money market funds, all other investment types do not have state investment limits. The State code limits money market funds to 20% of the portfolio. 3CE is within the State limit at 3.1%.

Cash and Investment Mix Holdings
Type Market Value
% of
Portfolio
Permitted by
CA Government Code
Cash and cash equivalents $90,914,600 40.8% 100%
Money Market Funds $6,833,221 3.1% 20%
U.S. Treasuries $125,140,959 56.1% 100%
Total $222,888,780 100.0%

The FY 2024-25 Adopted Budget, with appropriations of $730.3 million, included estimated investment revenues of $7.2 million. In the fourth quarter, investment earnings from operating and investment accounts netted $9.9 million, $4.9 million from interest on cash and money market accounts, and $4.9 million from short-term investments, mostly from Treasuries. Interest earned on 3CE collateral held by counterparties totaled $1.2 million. To date, the total investment and interest earnings from internal liquidity and counterparty collateral are $11.1 million. This year-end estimate is higher than the $10.8 million estimated in the mid-year budget forecast.

As of September 30, 2025, 3CE has 114 days of cash on hand. This is based on the total cash and equivalents of $222.9 million divided by an average daily expense of $1.9 million. Total operating expenses for FY 2024-25, less depreciation, are $712.4 million.

FISCAL IMPACT:

There is no fiscal impact to receiving this report.

CONCLUSION:
3CE continues to proactively diversify its financial institutional partnerships, including the recent addition of an operating account with West Coast Community Bank. The agency strategically deploys cash and short-term investments to capture favorable yields while maintaining sufficient liquidity to meet operating expenses and collateral requirements.

ATTACHMENT(S):

None.

Staff Report Item 9
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Gina Urmatan, Senior Accountant
SUBJECT: Financial Report for the period of October 1, 2024, through August 31, 2025 DATE: November 12, 2025
RECOMMENDATION:

Receive a financial report for the period October 1, 2024, through August 31, 2025.

SUMMARY:

Over the eleven months ending August 31, 2025, operating revenues amounted to $600.0 million, and operating expenses totaled $551.8 million for a net operating income of $48.2 million. Non-operating revenue of $10.1 million, driven by interest and investment returns, netted the month with a total net position increase of $58.3 million.

Year-to-date operating revenue is $71.9 million below budget, primarily due to a lower-than-expected retail load partially offset by settlement fund receipts. 3CE adjusted the forecast downward in March 2025 as part of the electric generation rate adjustments approved by the Policy Board effective April 1, 2025. Non-operating revenue from investment returns from assets held in operating and investment accounts, and interest on collateral exceeded the budget with a variance of $3.7 million due to higher-than-anticipated investment yields. Year-to-date total revenue (operating & non-operating revenue) is $68.2 million lower than the budget, an unfavorable variance of 10.0%.

Year-to-date operating expenditures excluding capital outlay are $72.9 million below budget, a variance of 11.7%. This variance is primarily attributable to lower-than-anticipated energy costs, which came in $64.8 million under budget. The reduction in energy expenses compared to the budget reflects a convergence of factors, including lower market prices, higher-than-expected wholesale energy sales, and increased revenue from congestion revenue rights. Additionally, Renewable Portfolio Standard

(RPS) compliance expenditures are below budget due to lower market prices for these attributes. Higher resource adequacy (RA) costs partially offset these favorable impacts because of elevated market prices.

Non-energy operating costs were $8.1 million lower than budget due to less-than-planned costs for contracted services, staff vacancies, and energy programs. The capital outlay was below budget by $12.7 million since capital projects are not recorded as direct expenditures. Instead, these projects are recorded as capital assets on the balance sheet and are expensed over time through depreciation following accounting principles. Year-to-date total expenditure, including capital outlay, is $85.6 million lower than the budget, a favorable variance of 13.4%.

The net position at the end of August 31, 2025, totaled $276.5 million, a $58.3 million increase from the start of the fiscal year. The increase is primarily due to prepaid expenses for RA, deposits held by counterparties to meet collateral requirements, and growth in accrued revenue, accounts receivable, and capital assets. The increase is further supported by reduced accounts payable, other accrued liabilities, and security deposits from counterparties. Cash, cash equivalents, and investments totaled $213.9 million, a $12.8 million decrease from the start of the fiscal year. The reduction in liquidity was primarily attributed to the elevated cost of electricity invoices, including the prepayment of expenses for RA.

FISCAL IMPACT:

There is no financial impact associated with receiving this report.

ATTACHMENT(S):

August 31, 2025 Financial Report

Compiled Financial Statements 1
Compiled Budgetary Comparison Schedule 6
Budget Variance Commentary 8
Investment Summary 9
Accounts Receivable Aging Summary 10
Table of Contents

FINANCIAL REPORT
Fiscal Year to Date
As of August 31, 2025

1 ACCOUNTANTS’ COMPILATION REPORT
Board of Directors
Central Coast Community Energy
Management is responsible for the accompanying financial statements of Central Coast Community Energy (a California Joint Powers Authority) which comprise the statement of net position as of August 31, 2025, and the related statement of revenues, expenses, and changes in net position, and the statement of cash flows for the eleven months then ended in accordance with accounting principles generally accepted in the United States of America. We have performed a compilation engagement in accordance with Statements on Standards for Accounting and Review Services promulgated by the Accounting and Review Services Committee of the AICPA. We did not audit or review the accompanying statements nor were we required to perform any procedures to verify the accuracy or completeness of the information provided by management. Accordingly, we do not express an opinion, conclusion, nor provide any assurance on these financial statements.

Management has elected to omit substantially all of the note disclosures required by accounting principles generally accepted in the United States of America in these interim financial statements.

Central Coast Community Energy’s annual audited financial statements include the note disclosures omitted from these interim statements. If the omitted disclosures were included in these financial statements, they might influence the user’s conclusions about the Authority’s financial position, results of operations, and cash flows. Accordingly, these financial statements are not designed for those who are not informed about such matters.

We are not independent with respect to the Authority because we performed certain accounting services that impaired our independence.

Maher Accountancy
San Rafael, CA
October 2, 2025
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com

Current assets
Cash and cash equivalents 118,029,196 $
Accounts receivable, net of allowance 58,196,911
Accrued revenue 43,631,896
Other receivables 2,325,198
Investments 90,876,892
Prepaid expenses 18,397,414
Deposits 30,063,348
Loan receivable 194,301
Total current assets 361,715,156
Noncurrent assets
Investments 5,005,300
Deposits 21,055
Loan receivable 1,135,778
Capital assets, net of depreciation and amortization 6,461,767 Total noncurrent assets 12,623,900
Total assets 374,339,056
Current liabilities
Accrued cost of electricity 80,085,390
Accounts payable 2,140,613
Other accrued liabilities 1,244,435
User taxes and energy surcharges due to other governments 2,012,394 Security deposits - energy suppliers 2,379,299
Lease liability 349,323
Total current liabilities 88,211,454
Noncurrent liabilities
Security deposits - energy suppliers 9,110,025
Lease liability 520,264
Total noncurrent liabilities 9,630,289
Total liabilities 97,841,743
Net investment in capital assets 5,519,964
Unrestricted 270,977,349
Total net position 276,497,313 $

NET POSITION
As of August 31, 2025

STATEMENT OF NET POSITION

CENTRAL COAST COMMUNITY ENERGY
ASSETS

LIABILITIES

OPERATING REVENUES
Electricity sales, net 591,790,598 $
Liquidated damages 8,101,745
Other income 85,968
Total operating revenues 599,978,311

OPERATING EXPENSES
Cost of electricity 514,491,001
Contract services 12,945,743
Staff compensation 9,447,004
Program incentives 12,422,142
Other operating expenses 1,900,665
Depreciation and amortization 559,127
Total operating expenses 551,765,682
Operating income (loss) 48,212,629

NONOPERATING REVENUES (EXPENSES)
Investment income 10,163,628
Interest and financing costs (42,642)
Gain (loss) on disposal of asset (1,745)
Nonoperating revenues (expenses) 10,119,241
CHANGE IN NET POSITION 58,331,870
Net position at beginning of period 218,165,443
Net position at end of period 276,497,313 $
Eleven Months Ended August 31, 2025

AND CHANGES IN NET POSITION

STATEMENT OF REVENUES, EXPENSES

CENTRAL COAST COMMUNITY ENERGY

CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from customers 575,215,262 $
Receipts of liquidated damages 8,101,745
Receipts from wholesale sales and other operating receipts 23,474,158 Receipts of deposits and collateral 52,686,774
Payments to suppliers for electricity (547,910,421)
Payments for other goods and services (15,226,743)
Payments of deposits and collateral (69,786,738)
Payments for program incentives (14,618,613)
Payments for staff compensation (9,342,136)
Payments of taxes and energy surcharges to other governments (9,831,800) Net cash provided by operating activities (7,238,512)

CASH FLOWS FROM CAPITAL AND RELATED

FINANCING ACTIVITIES
Payments of lease liability (340,007)
Purchases of capital assets (3,147,128)
Net cash provided (used) by capital and related financing activities (3,487,135)

CASH FLOWS FROM INVESTING ACTIVITIES
Investment income received 6,481,072
Proceeds from sales and maturities of investments 137,897,000 Principal payments received of loan receivable 190,718
Purchase of investments (166,353,628)
Net cash provided (used) by investing activities (21,784,838) Net change in cash and cash equivalents (32,510,485)
Cash and cash equivalents at beginning of year 150,539,681 Cash and cash equivalents at end of period 118,029,196 $ Change in fair value of investments 3,398,999 $
Change in interest income receivable 283,557 $

NONCASH CAPITAL FINANCING ACTIVITIES
Capital acquisitions included in accounts payable
and other liabilities 72,216 $
Eleven Months Ended August 31, 2025

STATEMENT OF CASH FLOWS

CENTRAL COAST COMMUNITY ENERGY

NONCASH INVESTING ACTIVITES

Operating income (loss) 48,212,629 $
Adjustments to reconcile operating income (loss) to net cash provided by operating activities
Depreciation and amortization expense 559,127
(Increase) decrease in:

Accounts receivable, net of allowance (13,759,016)
Accrued revenue (12,683,365)
Other receivables 4,321,890
Prepaid expenses (16,568,190)
Deposits (18,367,371)
Increase (decrease) in:

Accrued cost of electricity 3,312,144
Accounts payable (2,794,591)
Other accrued liabilities 456,085
User taxes and energy surcharges due to other governments 35,246 Security deposits - energy suppliers 36,900
Net cash provided by operating activities (7,238,512) $

CENTRAL COAST COMMUNITY ENERGY
STATEMENT OF CASH FLOWS (continued)
Eleven Months Ended August 31, 2025

RECONCILIATION OF OPERATING INCOME (LOSS) TO NET

CASH PROVIDED BY OPERATING ACTIVITIES

1 ACCOUNTANTS’ COMPILATION REPORT

Board of Directors
Central Coast Community Energy
Management is responsible for the accompanying special purpose budgetary comparison schedule of Central Coast Community Energy (a California Joint Powers Authority) for the one and eleven months ended August 31, 2025, and for determining that the budgetary basis of accounting is an acceptable financial reporting framework. We have performed a compilation engagement in accordance with Statements on Standards for Accounting and Review Services promulgated by the Accounting and Review Services Committee of the AICPA. We did not audit or review the accompanying statement nor were we required to perform any procedures to verify the accuracy or completeness of the information provided by management. Accordingly, we do not express an opinion, a conclusion, nor provide any assurance on this special purpose budgetary comparison statement.

The special purpose statement is prepared in accordance with the budgetary basis of accounting, which is a basis of accounting other than accounting principles generally accepted in the United States of America. This report is intended for the information of the Board of Directors of the Authority.

Management has elected to omit substantially all of the note disclosures required by accounting principles generally accepted in the United States of America in these interim financial statements.

Central Coast Community Energy’s annual audited financial statements include the note disclosures omitted from these interim statements. If the omitted disclosures were included in these financial statements, they might influence the user’s conclusions about the Authority’s financial position, results of operations, and cash flows. Accordingly, these financial statements are not designed for those who are not informed about such matters.

We are not independent with respect to the Authority because we performed certain accounting services that impaired our independence.

Maher Accountancy
San Rafael, CA
October 2, 2025
1101 Fifth Avenue, Suite 200 San Rafael, CA 94901 415 459 1249 mahercpa.com

Actual Budget Amount % Actual Budget Amount % Budget
Annual Budget
Less Actual
YTD

REVENUES AND OTHER SOURCES
Electricity sales, net $ 71,235,846 $ 76,188,025 $ (4,952,179) -6% $ 591,790,598 $ 671,830,632 $ (80,040,034) -12% $ 745,962,356 $ 154,171,758 Revenue for damages - - - na 8,101,745 - 8,101,745 n/a - (8,101,745) Interest and investment returns 1,002,316 583,333 418,983 72% 10,163,628 6,416,663 3,746,965 58% 7,000,000 (3,163,628) Other income 5,271 5,700 (429) -8% 84,223 62,700 21,523 34% 68,400 (15,823) Total revenues and other sources 72,243,433 76,777,058 (4,533,625) -6% 610,140,194 678,309,995 (68,169,801) -10% 753,030,756 142,890,562

EXPENDITURES AND OTHER USES
Current Expenditures
Cost of energy 78,619,721 89,623,952 11,004,231 12% 515,898,244 580,699,508 64,801,264 11% 665,267,116 149,368,872 Salaries and benefits 1,099,897 1,048,820 (51,077) -5% 9,447,004 11,537,021 2,090,017 18% 12,585,842 3,138,838 Services and supplies 2,999,527 2,931,483 (68,044) -2% 26,201,313 32,246,308 6,044,995 19% 35,177,798 8,976,485 Capital outlay 9,123 1,443,167 1,434,044 99% 3,167,033 15,874,833 12,707,800 80% 17,318,000 14,150,967 Total current expenditures 82,728,268 95,047,422 12,319,154 13% 554,713,594 640,357,670 85,644,076 13% 730,348,756 175,635,162 Surplus (deficit) (10,484,835) $ (18,270,364) $ 7,785,529 $ 55,426,600 $ 37,952,325 $ 17,474,275 $ 22,682,000 $ (32,744,600) $ Annual

CENTRAL COAST COMMUNITY ENERGY

BUDGETARY COMPARISON SCHEDULE
One Month and Eleven Months Ended August 31, 2025
Month
Variance
Favorable
(unfavorable)
Year-To-Date
Variance
Favorable
(unfavorable)

CCA Program surplus/(deficit)
per budgetary comparison schedule: 55,426,600 $
Adjustments needed to reconcile to the changes in net position in the Statement of Revenues, Expenses and Changes in Net Position:

Add back GASB 87 lease amortization not in operating budget 297,364 Subtract depreciation expense (559,127)
Add back capital asset acquisitions 3,167,033
Change in Net Position 58,331,870 $

REVENUES, EXPENSES AND CHANGES IN NET POSITION

CENTRAL COAST COMMUNITY ENERGY

BUDGET RECONCILIATION TO STATEMENT OF
Eleven Months Ended August 31, 2025

Budget Item YTD Variance Comment
Electric Sales Revenue (11.9%) Sales revenue includes revenues actually billed to customers as well as estimated customer usage during the reporting period that is not yet billed.

Cost of Energy (11.2%) Variances in this category are typically due to (1) timing difference between projected and actual REC deliveries, (2) variance from actual to anticipated market prices, and (3) variance from actual to expected volume used by customers. Cost of energy includes scheduling coordinator fees for budget purposes only.

Staffing (18.1%) Staffing expenses are under budget due to the timing of new hires.

Professional Services (31.2%) This category includes accounting, IT, technical and other consultants.

Legal Costs (50.5%) This category includes outside legal costs for regulatory and energy procurement needs.

Marketing and customer enrollment (25.0%) Variance is mostly due to the lower than anticipated costs of recent customer enrollments.

Data Management Services 1.6% These fees non-discretionary and are charged on a per customer basis.

Utility Service Fees (4.9%) These are PG&E and SCE fees charged on a per customer basis.

Other General & Administrative (62.4%) This category includes occupancy costs, industry membership dues, and other general and administrative costs.

Energy and Related Programs (1.3%) Programs expenses have generally been delayed until future periods Budget Commentary for significant items

CENTRAL COAST COMMUNITY ENERGY
October 1, 2024 through August 31, 2025

Return of Investments YTD Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep

CASH AND CASH EQUIVALENTS
River City Bank/ Chase - Money Market and
other Interest Earning Accounts
Funds Invested - Average Balance $ 114,669,913 99,664,821 $ 87,375,820 $ 86,192,993 $ 97,066,887 $ 102,454,815 $ 111,974,304 $ 107,649,306 $ 103,295,944 $ 82,696,308 $ 90,158,778 $ Gains/Losses/Interest $ 380,768 3,882,039 $ 421,162 $ 324,104.99 317,642.68 320,213.20 371,348.25 391,318.15 386,324.48 356,934.61 292,737.82 319,484.99 Average APY 4.58% 4.41% 4.45% 4.42% 3.96% 4.35% 4.19% 4.31% 4.15% 4.25% 4.25%

INVESTMENTS
Schwab/Fidelity
Funds Invested - Average Balance $ 126,158,519 125,703,797 $ 126,652,212 $ 127,096,361 $ 127,561,770 $ 127,989,614 $ 128,449,074 $ 128,806,745 $ 129,263,682 $ 129,646,474 $ 130,201,722 $ Gains/Losses/Interest $ 451,482.54 4,903,361 308,267.24 504,316.11 576,572.23 414,554.41 494,803.49 379,880.26 240,759.17 497,644.42 464,926.16 570,155.31 Average APY 4.31% 2.93% 4.78% 5.44% 3.90% 4.64% 3.55% 2.24% 4.62% 4.30% 5.25%

CENTRAL COAST COMMUNITY ENERGY
Investment Summary
October 1, 2024 through August 31, 2025

Current 0 - 30 Days 31 - 60 Days 61 - 90 Days > 91 Days A/R Balance $ 14,615,893 31,900,132 $ 2,758,716 $ 814,379 $ 8,107,791 $ 58,196,911 $

CENTRAL COAST COMMUNITY ENERGY
Summary of Accounts Receivable, Net of Bad Debt Allowance As of August 31, 2025

Staff Report Item 10
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Inaara Muhammad, Manager of Energy Programs SUBJECT: FY 2024-25 Energy Programs Update
DATE: November 12, 2025
RECOMMENDATION:

Receive an update on 3CE’s Energy Programs.

BACKGROUND:
3CE’s Energy Programs have been administered since 2019 to support 3CE’s mission by serving the Central Coast community with incentives to engage in electrification initiatives, strengthen the local economy, and reduce greenhouse gas emissions. The Energy Programs portfolio has undergone several iterations to improve community-wide accessibility and strengthen participation for priority communities. Currently, 3CE offers 10 programs and two pilots to support residential, commercial, and public agency electrification efforts in the transportation, building, and agricultural sectors.

DISCUSSION/ANALYSIS:

As part of 3CE’s commitment to customers, 3CE staff continually evaluate Energy Programs’ performance by tracking several key indicators and using this analysis to improve the impact of 3CE’s Energy Programs.

The fourth quarter of FY 2024-25 showed increased participation in 3CE's Energy Programs, largely due to increased interest in building electrification opportunities among underserved communities, urgency in residential electrification due to federal funding decisions, and new member agencies engaging in electrification planning.

The table below highlights the agency’s programs’ impact through the start of Q4 2025, as compared to the prior fiscal year.

FY 2023-24 FY 2024-25 (as of late-Sept.)
GHG reductions Over 3,700 MT CO2e Over 5,300 MT CO2e
Load shifted 0 kWh Over 2.3 MWh daily
Table 1: Energy Programs Impact in FY 2023-24 and 2024-25(to date) 3CE’s Energy Programs Portfolio Analysis Update (Attachment 1) provides a detailed look at individual Energy Programs in FY 2024-25, showing data collected through late-September 2025. The update shares a variety of program performance metrics, including customer participation, all-electric purchases and installations, reduced greenhouse gas emissions, and performance on equity (e.g., incentives and support for income-qualified customers). The update also describes strategic initiatives currently underway to enhance 3CE’s Energy Programs portfolio through pilots and new program offerings.

Below are several ongoing strategic initiatives across Energy Programs’ focus areas. Complete data for FY 2024-25 will be finalized in Q1 of FY 2025-26 and presented in 3CE’s Annual Energy Programs portfolio evaluation.

Transportation Electrification
EV Charger Asset Pilot: Construction is ongoing for EV Charging at 3CE’s Soquel office for three, Level 2 chargers. The project is on track for completion and activation in November 2025. This pilot will provide staff with direct access to charging and support clean transportation adoption.

Building Electrification
Electrify Your Home: On October 1st, 3CE relaunched the Electrify Your Home Program which supports residential customers transitioning to all-electric heat pump technology for space and water heating. 3CE staff, in collaboration with the Community Advisory Council, developed several enhancements to the program including expanded contractor eligibility, new eligible appliances, and a customer-focused application.

Moreover, bringing program administration in-house will leverage 3CE staff expertise to improve customer experience and streamline program operations.

Agricultural Electrification
Ag Electrification Program: On October 1st, 3CE’s Community Advisory Council received a presentation on electrification challenges and opportunities in the agricultural sector.

Next, staff will collect feedback from agricultural stakeholders across 3CE’s service area

on potential program enhancements to support electrification. Presentations and focus group meetings will be held in all five counties in November and December 2025.

Energy Optimization
Distributed Energy Resources Management System (DERMS) / Virtual Power Plant (VPP):

On October 24th, 3CE published a Request for Proposals seeking a vendor to provide a DERMS platform and related implementation services. The DERMS will serve as a core platform for 3CE’s VPP and Distributed Energy Resources (DER) pilot programs. 3CE’s customer relationship management system, which was implemented last fiscal year, has enabled energy programs to remain open as 3CE transitions into FY 2025-26. 3CE’s website has been updated to communicate any changes to programs effective at the start of the fiscal year.

FISCAL IMPACT:

There is no fiscal impact associated with this report and update.

CONCLUSION:
3CE’s Energy Programs support California’s Central Coast communities by providing funding and services to accelerate regional electrification, reduce greenhouse gas emissions, and benefit local customers and economies.

ATTACHMENT(S):

1. 3CE Energy Programs Analysis Update

3CE’s Energy Programs Update
This report provides updates on Central Coast Community Energy’s (3CE) Energy Programs and Pilots. 3CE continually tracks energy programs’ growing participation and impact in reducing greenhouse gas emissions and supporting the local economies in which 3CE customers live and work. Data in this report is current as of late September 2025. Complete data for FY 2024-25 will be finalized in Q1 of FY 2025-26 and presented in 3CE’s Annual Energy Programs portfolio evaluation.

The table below highlights the agency’s programs’ impact through the start of Q4 2025, as compared to the prior fiscal year.

IMPACT FY 2023-24 FY 2024-25 to date
GHG reductions Over 3,700 MT CO2e Over 5,300 MT CO2e
Load Shifted 0kWh Over 2.3 MWh daily
Heat Pump Water Heater & HVAC
Units
396 units 1,104 units
All-Electric New Construction 460 units 302
E-Buses 18 E-buses 17 E-buses
Electric Vehicles 1,108 EVs 1,008 EVs
EV Chargers 819 EV Chargers 1,063 EV Chargers
Ag Equipment 18 rebates 22 rebates
Total Incentives Distributed $11 million $15 million
3CE’s energy programs’ impact continues to increase, serving 3CE’s mission to support all customers in their transition to renewable resources, to drive GHG emissions reductions, and to promote local economic growth across the Central Coast.

Transportation Electrification

1.Electrify Your Ride
Over 4,200 MTCO2e avoided
Equal to 980 gas cars off the road for one year
Program Purpose & Overview
Electrify Your Ride (EYR) is 3CE’s flagship transportation program, intended to reduce GHG emissions and increase EV adoption by providing residential and commercial customers with rebates for EV purchases and EV charger installations. Program funds are available first come, first served. Enhanced incentives are available for CARE/FERA customers, or income-qualified participants. Technical assistance is available for multifamily and commercial customers planning EV charging projects.

Over $47M in all-electric purchases
supported
Over 1,800 applications approved
across all 5 counties
Figure 1.1: % of applications across counties
Over 32% rebates to income-qualified
customers
Figure 1.2: Incentive distribution to income-qualified
customers
2,811 EV, EV Charger, and Electrical
Upgrades supported this fiscal year
Figure 1.3: Rebates approved by incentive
type
Over 26 commercial and multi-family
customers receiving technical assistance

Transportation Electrification

2.Electric Bus (E-bus) Program
Over 410 tCO2e avoided, equal to 17 Type A buses
off the road for one year
Program Purpose & Overview
3CE’s Electric Bus program enables public sector electrification by incentivizing all-electric buses throughout the 3CE service area. The program reduces GHG emissions and harmful pollutants from public transportation serving students, farmworkers, and community members.

Program funds are available first come, first served, and can be assigned to a manufacturer. All funded E-buses must be domiciled and charged at 3CE-enrolled sites. 2 transit agencies & 6 school
districts supported across all five
counties
Figure 2.2: % rebates distributed across counties
17 all electric buses supported
all-electric bus purchases supported
24% of buses to a Title 1 school or
disadvantaged community (DAC)
Figure 2.1: % buses for DAC/Title 1 School
$14.3M in all-electric
purchases enabled
through 3CE’s E-Bus
program
Figure 2.3: Rebates approved by e-bus type

Transportation Electrification

3.Plan, Charge, and Electrify Your Fleet
12 Member Agencies committed to zero-emission fleet planning and implementation
Program Purpose & Overview
3CE’s Fleet Electrification programs reduce GHG emissions from medium and heavy-duty fleets by providing Member Agencies with incentives and technical assistance for zero-emission fleet planning and implementation at 3CE-enrolled sites. Program funds are available first come, first served.

Incentive Offerings:
- PLAN: Plan Your Fleet (PYF) provides no-cost technical assistance including fleet replacement planning, project design and engineering, EV charging recommendations, and funding plans.
- CHARGE: Charge Your Fleet (CYF) provides rebates for Level 2 EV Chargers and Level 3 DC Fast Chargers purchase and installation.
- ELECTRIFY: Electrify Your Fleet (EYF) provides rebates for electric vehicle purchase or lease, covering light, medium, and heavy-duty vehicles, plus electric motorcycles.

Program Design Updates
Oct. 1st, 2025: To streamline access and expand funding opportunities, 3CE has combined fiscal-year rebate caps for the Electrify Your Fleet and Charge Your Fleet programs. Member Agencies are eligible for up to $300,000 in total funding for the purchase or installation of electric vehicles, EV supply equipment, and associated infrastructure.

Cities and Counties engaged in zero-emission fleet
planning and implementation include…
4 cities and
counties
Developing
Fleet
Replacement
Plans
7 cities and
counties
Developing
charging
infrastructure plans
and/or site designs
Over 900kW in EV charging
capacity installed this fiscal year
Over $2.4 million in all-electric
purchases and installations supported
Figure 3.1: rebates distributed by incentive type

Transportation Electrification

4.EV Charger Asset Pilot
Nine Level 2 and two DC Fast Chargers planned across three pilot sites
Program Purpose & Overview
3CE’s EV Charger Asset Pilot addresses the need for additional Electric Vehicle Supply Equipment (EVSE) and infrastructure across the 3CE service area through the deployment of a phased EV Charger asset ownership program. The pilot examines charger asset ownership as a potential step in advancing equitable transportation electrification solutions across 3CE’s service area. The pilot encompasses Level 2 and Level 3 DC Fast Charger design, construction, and operation across three categories: community resilience hubs, corridor charging, and EVSE at Member Agency sites.

Board Decisions
December 11, 2024: The Policy Board approved an EV charger capital project at 1026 Palm Street in San Luis Obispo as part of 3CE’s EV Charger Asset Pilot.

June 18, 2025: The Policy Board approved an EV charger project at 3CE’s Santa Cruz office located at 2601 Porter Street in Soquel as an additional workplace charging pilot site.

October 15, 2025: The Executive Committee approved a publicly accessible EV charging project at 421 South McClelland Street in Santa Maria.

Pilot Updates
Workplace Charging at 3CE’s San Luis Obispo Office: EV Charger installation and activation is complete for three Level 2 chargers, which offer a total of five charging ports. Employee access to charging began in September 2025. Since the Board’s initial approval in December 2024, EV ownership among San Luis Obispo office employees has increased by 50%, reinforcing the value of accessible workplace charging.

Workplace Charging at 3CE’s Soquel Office: Construction began in September 2025 for three, Level 2 EV charging stations. The project is on track for completion and activation with ChargePoint by November 2025, with employee charging access beginning the same month.

Public Charging in Santa Maria: The Executive Committee approved the project on October 15, 2025. Engineering design and permitting are complete. The site lease agreement is scheduled for Santa Maria City Council review by the end of October 2025. Construction will begin shortly after Council approval, with completion anticipated by Q3 of FY 2025-26.

Future Pilot Sites: 3CE staff are exploring additional pilot locations for EV charging in consideration of designing and implementing an EV Charging Master Plan. Additional sites will further inform 3CE’s examination of agency-managed infrastructure as a means to expand access to EV charging throughout the Central Coast.

Building Electrification

5.Electrify Your Home Program
Over 971 MT CO2e avoided, equal to over
130 homes’ energy use for one year
Program Purpose & Overview
3CE's Electrify Your Home Program (EYH) promotes residential building decarbonization by replacing fossil-fuel powered water heating and space heating equipment with high-efficiency electric and heat pump appliances for single family and multifamily properties. Contractors complete the application process and pass the full value of the rebate to the customer. Program funds are available first come, first served.

Board Decisions
April 9th, 2025: The Operations Board authorized the sixth amendment to 3CE’s agreement with Energy Solutions. The Amendment revised the scope of work to bring incentive check processing in house, reducing the total not to exceed amount by $735k. The amendment enabled program stability and budgetary flexibility through the end of the fiscal year.

Program Design Updates
July 3rd, 2025: The EYH program was paused to new applications due to unusually high participation rates which exceeded available funding. EYH will relaunch on October 1st and include expanded eligibility guidelines to retroactively rebate customers who purchased appliances during the pause period. 3CE is incorporating recommendations from the agency’s Community Advisory Council (CAC) to expand Electrify Your Home offerings in FY 2025-26.

July 7th, 2025: 3CE published a request for proposals seeking a program facilitator for its Virtual Home Assessment pilot, which will launch in Spring 2026.

Figure 5.2: Income-qualified participants by
county
60% of rebates distributed to income-qualified customers 1,390 rebates in fiscal year 2024-25
Figure 5.1: Rebates approved by incentive type
EYH supported over 45 unique, local installers across five counties to complete over $12.1 million in all-electric and heat pump installations

Building Electrification

6.New Construction Electrification Program
302 new, all-electric housing units built across 3CE’s service area Program Purpose & Overview
3CE’s New Construction Electrification Program (NCEP) reduces GHG emissions by incentivizing the development of all-electric housing in 3CE’s service area. NCEP provides housing developers incentives to build all-electric housing projects including water heating, space heating, and cooking appliances. Enhanced incentives are available for affordable housing projects and single-family disaster rebuilds. Program funds are available first come, first served.

Figure 6.1: all-electric housing units incentivized by county 44 applications across four counties for the construction of… NCEP supported over 16 local
contractors to build all-electric
housing across 3CE’s service area
All-electric
Accessory
Dwelling Units
All-electric
Disaster Rebuilds
All-electric Market
Rate Housing Units
All-electric
Affordable Housing
Units
2 5 34 261
183 59
55 5
Santa Cruz County
Monterey County
San Luis Obispo
County
Santa Barbara
County

Building Electrification

7.Reach Codes Program
Codes adopted by 3CE’s cities & counties are
anticipated to impact 310 permits per year
Program Purpose & Overview
3CE’s Reach Code program reduces GHG emissions from the built environment by providing technical assistance to 3CE Member Agency jurisdictions to adopt and codify “Reach Codes” that promote building electrification and EV infrastructure. Technical assistance includes customized code language development, staff presentations, board advocacy, and code enforcement tool creation.

Implemented reach codes update local building codes and ordinances for new residential and commercial construction, and major remodel projects, and align with the 2022 California statewide building code update.

Board Decisions
April 9th, 2025: The Operations Board approved an amendment to 3CE’s contract with TRC Engineers, 3CE’s technical support vendor for Reach Codes. The amendment increased the not-to-exceed amount listed in the contract by $385,000 and extended the term of the agreement by two years to allow for continued and uninterrupted services to support the Reach Codes program. The amendment also added additional services for code updates, and outreach to engage new Member Agencies with the program.

Program Design Updates
3CE is closely monitoring impacts from recent legislative decisions and exploring available support opportunities.

CODE TYPE & IMPACT
Single Family Existing Buildings-Flexpath: Flexible menu of energy efficiency, electrification, and electric readiness measures for
major renovations
Single Family Existing Buildings- Air
Conditioning to Heat Pump: Property
owners follow energy efficiency measures or install
heat pump technology at time of replacement
Electric Vehicle Infrastructure: Increases
EV charging spaces for new developments and
remodel projects beyond CAL Green code
requirements
0 1
2 City of
San Luis
Obispo
City of
Santa
Cruz
City of
Goleta
# of Codes
5 Reach Codes adopted or
codified across 3 cities
Figure 7.2: Types of Reach Codes pursued
Figure 7.1: # of codes by city

Agricultural Electrification

8.Agricultural (Ag) Electrification Program
182.5 tCO2 avoided, equal to 12 tractors off the fields for one year Program Purpose & Overview
3CE’s Agricultural (Ag) Electrification program avoids GHG emissions associated with fossil fuel-powered agricultural equipment by incentivizing the purchase of all-electric equipment alternatives. The program provides rebates to 3CE customers in and/or supporting the agricultural industry for all-electric equipment purchases to support business operations.

Enhanced incentives are available for small businesses and businesses that experienced loss/damage of equipment due to declared natural disasters. Customers are eligible for up to two rebates per fiscal year, and program funds are available first-come, first-served. 20 customers supported across all
five counties
Figure 8.1: % participation by county
90% of rebates to small businesses
Figure 8.2: % rebates to small businesses by
county
3CE incentives leveraged for over $1.66 million in all-electric purchases 3CE incentives leveraged for over $1. including66…million in all-electric purchases including…

Energy Optimization
13% 1%
54%
18%
14% Monterey County
San Benito County
San Luis Obispo
County
Santa Barbara
County
Santa Cruz County
2300
0 500
1000
1500
2000
2500
kWh of load shifted
daily
(4-9 PM)
Month

9.Residential Battery Rebate Program
Over 3.6 MWh of battery capacity installed this
fiscal year across 3CE service area
Program Purpose & Overview
3CE’s Residential Battery Rebate Program achieves load shifting during peak hours through rebates for the purchase and installation of residential, behind-the-meter battery systems. The program helps solar and non-solar customers manage energy consumption, respond to price signals, and reduce demand during net peak hours. Program funds are available first-come, first-served. Customers enrolled in NEM 2.0 who elect to transition to NBT early, CARE/FERA-enrolled customers, and customers designated as medical baseline are eligible for enhanced incentives. Batteries must be programmed to discharge 50% of capacity daily between 4 p.m. and 9 p.m.

Program Design Updates
February 2025: Staff introduced a new scheduling assistance service to help customers meet the program’s discharge requirements. Staff are conducting direct outreach to rebate applicants to facilitate their enrollment.

Over 2.3 MWh load shifted daily during peak hours
Figure 9.1: daily load shift during peak hours
238 applications across all five
counties
Figure 9.2: % participation by county
Over 14% of applications from
CARE/FERA or Medical Baseline
enrolled customers
193 customers using scheduling
assistance
Over 52 local
contractors actively
installing battery
systems for 3CE
customers

Energy Optimization

10. Hourly Flex Pricing Pilot 1 & 2
Over 17,000 MWh annual load enrolled
Program Purpose & Overview
3CE’s Hourly Flex Pricing (HFP) Pilot offers customer savings and operational benefits to agricultural, residential, and commercial 3CE customers through real-time, dynamic price signals. In partnership with PG&E, both Pilot 1 (agricultural) and Pilot 2 (commercial and residential) offer a variety of Automation Service Providers (ASPs) to help enrolled customers optimize load in response to hourly price signals. Expanded Pilot 1, implemented in partnership with Polaris Energy Services, also includes system reliability benefits for agricultural customers through incentivized equipment automation. HFP Pilots 1 and 2 are currently in their first year of implementation.
73% of annual load enrolled from
commercial meters
Figure 10.1: load enrolled by customer type
70 meters across all three
customer classes
Figure 10.2: pilot participation by customer
type

Staff Report Item 11
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Jerri Strickland, Director of Regulatory Affairs and Compliance SUBJECT: CPUC Regulatory Update
DATE: November 12, 2025
RECOMMENDATION:

This recommends the Operations Board receive the attached CPUC Regulatory Update.

DISCUSSION/ANALYSIS:

Please find attached 3CE’s Regulatory Update, providing the latest information on the following:
 Resource Adequacy (RA)
 Bioenergy Market Adjustment Tariff (BioMAT)
 Demand Response (DR)
 Integrated Resource Planning (IRP)
 Interconnections
 PG&E Rule 30 Application
 Improvements to Climate Credit
 Energy Resources Recovery Account (ERRA) Forecast
 General Rate Cases
 Demand Flexibility
 Integrated Energy Policy Report
 Disconnections
FISCAL IMPACT:

No financial impact by receiving this report.

CONCLUSION:

This is an informational item only.

ATTACHMENT(S):

Regulatory Update

Operations Board Update
November 12, 2025

Table of Contents
REGULATORY UPDATE......................................................................................................................................................... 3 Resource Adequacy (RA) -.............................................................................................................................................. 3 Bioenergy Market Adjustment Tariff (BioMAT) - ................................................................................................. 3 Demand Response – .......................................................................................................................................................... 4 Integrated Resource Planning (IRP) -........................................................................................................................ 4 Interconnections - .............................................................................................................................................................. 6 PG&E Rule 30 Application for Transmission Service .......................................................................................... 6 Improvements to the Climate Credit.......................................................................................................................... 7 Energy Resources Recovery Account (ERRA) Forecast...................................................................................... 7 General Rate Cases............................................................................................................................................................. 8 Demand Flexibility............................................................................................................................................................. 9 Integrated Energy Policy Report 2025 –................................................................................................................... 9 Disconnections – ..............................................................................................................................................................10

REGULATORY UPDATE
Resource Adequacy (RA) - R.25-10-003
Issue
The Resource Adequacy (RA) program is the California Public Utilities Commission’s (CPUC) main grid reliability planning program. All load serving entities (LSEs) under the CPUC’s jurisdiction, including CCAs, must demonstrate purchase of a specified amount of eligible RA generation capacity each month and year to comply with RA program requirements. Increasing demand for and a decreasing supply of eligible RA capacity over the past five years have resulted in sharply increased prices and unprecedented difficulty procuring sufficient RA to achieve compliance.

Status
The Commission has opened a new proceeding to address the 2027 and 2028 RA compliance year and consider further refinements to the slice-of-day (SOD) framework. The preliminary scope of the proceeding, issued October 15, includes accreditation methodologies for long-duration energy storage resources, development of an unforced capacity (UCAP) framework to account for historical forced outage rates in the RA values of certain resources, and consideration of an hourly load obligation trading mechanism, which 3CE has strongly supported given its potential affordability benefits. The Commission scheduled workshops on November 3 and 4 to initiate stakeholder conversations on items in scope, particularly on RA counting rules for long-duration energy storage and UCAP proposals.

Next Steps
3CE’s final 2026 year-ahead RA filing is due October 31. 3CE will become a party to the new RA proceeding and will work with CalCCA to submit comments on the preliminary scope of the proceeding, which will be formally set in December. Stakeholder proposals are due in late January. 3CE will continue to advocate for refinements to the SOD program that balance grid reliability with affordability.

Bioenergy Market Adjustment Tariff (BioMAT) - R.22-10-010; A.25-08-015 Issue
BioMAT is a procurement program opened in 2015 to encourage the development of small bioenergy projects in California. The program is unique in that it allows load serving entities (LSEs) contracting with these projects to recover the costs from all California electricity users through the Public Purpose Programs (PPP) charge. In 2021, 3CE and other CCAs successfully lobbied legislators to reverse the exclusion of CCAs from BioMAT with the passage of AB 843. AB 843 was the first time CCAs gained access to PPP funding, setting a valuable policy precedent. The CPUC began implementation of AB 843 in October 2022 by opening of a new proceeding to work through the details of CCA participation. On August 14, 2024, 3CE’s Operations Board approved 3CE’s participation in the BioMAT program and authorized 3CE’s CEO to execute PPAs with BioMAT-eligible projects.

Status
On August 29, 3CE submitted the first-ever CCA application for compliance review regarding 3CE’s administration of the BioMAT program. The application and supporting testimony describe 3CE’s compliance with the BioMAT program requirements and 3CE’s prudent management of its BioMAT PPA.

PG&E was the only party to submit a response to 3CE’s application, stating its intention to participate in the proceeding and suggesting that formal hearings may be necessary. 3CE replied to PG&E’s comments, maintaining that the limited scope of its application does not warrant this additional administrative process. Separately, the Commission issued a Proposed Decision (PD) that denies a petition filed by the

Bioenergy Association of California to extend the BioMAT program beyond its current end date of December 31, 2025. This PD does not impact 3CE’s current BioMAT PPA.

Next Steps
The prehearing conference for 3CE’s application is scheduled for November 19, which will determine the parties, scope of issues, proceeding schedule, and other procedural matters. 3CE will be engaged in its application proceeding and will continue to demonstrate compliance with BioMAT program requirements in order to seek cost recovery for the project once it comes online, currently scheduled for 2027.

Demand Response – R.25-09-004
Issue
Demand response (DR) refers to programs and rate structures that encourage customers to adjust or reduce their electricity usage in response to price signals, grid conditions, or market incentives. By shifting consumption away from peak periods or reducing load during times of grid stress, DR helps maintain system reliability, reduce the need for costly peaking resources, and integrate higher levels of renewable generation. Well-designed DR programs also empower customers to take a more active role in managing their energy use while contributing to California’s clean energy transition and greenhouse gas reduction goals. On September 29, 2025, the Commission opened this proceeding to enhance demand response in California, along with a staff report proposing to update demand response guiding principles based on predictability, reliability, consistency, cost-effectiveness, and to support the State's energy and environmental goals.

Status
The Commission plans to re-examine and improve Key DR policies, including Dual Participation Policy, Valuation Methodologies, and Evaluation Metrics. The OIR states that the Commission will consider amendments to ensure continued alignment with the evolving DR landscape and the state’s policy goals and plans to bring new topics and proposals.

Next Steps
3CE staff are working with CalCCA to develop opening comments to the OIR which are due November 13, 2025. Key issues for 3CE include pursing systems and processes that support timely and consistent CCA access to customer data, ensuring CCA customers have equitable access to demand response resources, and ensuring new polices or programs do not encroach on CCA rate and program autonomy.

Integrated Resource Planning (IRP) - R.20-05-003; R.25-06-019 Issue
Integrated Resource Planning (IRP) is the CPUC’s greenhouse gas (GHG) reduction planning program.

LSEs must submit IRPs every two years demonstrating that planned future procurement will produce GHG emissions below an assigned benchmark while contributing to a resource fleet that meets sector-wide GHG targets and maintaining grid reliability. Previous IRP cycles have produced three procurement mandates, which apply to 3CE and other CCAs. On April 18, the CPUC issued an Amended Scoping Memo stating its intent to address additional issues in the IRP proceeding, including implementation of Assembly Bill (AB) 1373 which allows the Commission to request that the Department of Water Resources (DWR) serve as a central procurement entity (CPE) for certain long-lead time (LLT) resources,

as well as development of a long term procurement framework entitled the Reliable and Clean Power Procurement Program (RCPPP) that would replace the CPUC’s current ad hoc mandate structure.

Status
On September 26, the Commission issued a Decision on a petition filed by Southern California Edison requesting modification to the Mid Term Reliability procurement requirements. The Decision eliminates the ability for LSEs to use short-term bridge contracts to cover for delayed contracts, instead determining that LSEs experiencing delays will still be compliant with MTR obligations if they can show that they have executed sufficient long-term contracts to meet the applicable procurement obligation and have met month-ahead resource adequacy requirements in all months in which the contract is delayed. Separately, the Commission issued a draft Resolution adopting a new IRP citation program that would issue penalties for late or incomplete IRP planning and procurement filings. CalCCA’s comments on the draft Resolution incorporated 3CE’s recommendations that LSEs should be provided with adequate time to respond to citations and flexibility when filing delays are caused by factors outside of their control.

New IRP Venue
The CPUC opened a proceeding, R.25-06-019, as a new primary venue for oversight of the IRP process, including the next individual LSE IRP filings. The CPUC will also take up RCPPP development and implementation in the new proceeding after adopting a directional framework in the current IRP venue.

On September 30, CPUC staff issued a Ruling recommending an additional procurement order during 2029-2032 of 1,500 MW annually for a total of 6,000 MW, allocated to all LSEs on a load-share basis. The Ruling requested party feedback on the necessity of a near-term procurement order and whether the proposed volume and schedule of procurement is feasible. 3CE worked closely with CalCCA to develop comments cautioning against a procurement order, given potential negative market and affordability impacts, significant barriers such as federal policy changes and interconnection delays, and the uncertainty of forecasted load growth, instead encouraging the Commission to prioritize the development of a predictable long-term procurement framework. CalCCA’s comments recommend that if the Commission does issue an interim procurement order, it should order an initial tranche of 2,000 MW for 2029-2030 and reassess the need for additional procurement in 2031-2032 in case forecasted load growth does not materialize.

Next Steps
A forthcoming scoping memo in the new IRP proceeding will provide clarity on the schedule and deadline for the next IRP cycle. In the meantime, the Commission has issued draft materials, which 3CE has begun to test in preparation for its IRP development. 3CE is also reviewing party comments on the Ruling related to an interim procurement order in preparation for reply comments, due October 31.

Distributed Energy Resource Interconnections – R.25-08-004 Issue
The Commission has recently opened a proceeding to update distribution-level interconnection rules for distributed energy resources (DERs) under the existing Rule 21, which describes requirements for generation facilities to connect to an IOUs’ distribution and transmission system. The rulemaking will consider refinements to existing DER interconnection processes, Rule 21’s relationship to the utilities’ Wholesale Distribution Access Tariffs (WDAT), cost containment measures, and associated interconnection procedures concerning grid safety and reliability. CCAs are not responsible for

administration of Rule 21, but the tariff and associated DER interconnection procedures can impact CCAs’ ability to enroll, interconnect, and manage DER in their programs.

Status
The preliminary scope of the proceeding includes potential reforms to electrical independence tests, interconnection processes, technical requirements, Rule 21 implementation costs, and communication protocols and interoperability of DERs, among other issues. CalCCA submitted comments on the preliminary scope recommending consideration of non-IOU owned DERs and emphasizing the importance of updating Rule 21 to reflect evolving technologies and adoption trends.

Next Steps
Reply comments on the preliminary scope are due November 10. 3CE will continue to track changes to interconnection processes that may impact 3CE customers and support outcomes that would streamline DER interconnection processes.

Interconnections - IPE 5.0
Issue
The California Energy Commission’s (CEC) 2023 Integrated Energy Policy Report (IEPR) identifies interconnection delays as a significant barrier to achieving California’s electrification and decarbonization goals. Ongoing initiatives led by various entities are working to address this issue and streamline processes for connecting clean resources to the grid. One such effort is CAISO’s Interconnection Process Enhancements (IPE) 5.0 initiative, focused on modifications to recent interconnection reforms aiming to prioritize and accelerate the onboarding of viable projects capable of meeting near-term reliability needs and state policy objectives. .

Status
On October 13, the CAISO posted a draft final proposal for the current IPE initiative, which includes a pathway to allow Energy-Only (EO) projects that have achieved commercial operations to seek deliverability. Without deliverability, resources cannot provide Resource Adequacy (RA) capacity. This represents a significant positive shift from CAISO’s initial proposal, which declined to open a pathway for EO projects to seek and receive deliverability, resulting from 3CE’s advocacy through CalCCA that it is crucial to widen the pool of resources that can provide RA value.

Next Steps
3CE will continue tracking the initiative and encourage reform to accelerate and streamline the interconnection process, including changes that will increase the availability of clean energy resources Comments on the draft final proposal are due November 3. CAISO will then formally issue a final proposal, which it plans to take to its Board of Governors in March of 2026 for approval.

PG&E Rule 30 Application for Transmission Service– A.24-11-007 Issue
On November 21, 2024, PG&E submitted an Application to the CPUC requesting approval of a new rule for non-residential customers requesting interconnection at transmission-level voltages, citing a recent increase in customers such as data centers requesting transmission-level interconnections. Current PG&E rules are focused on distribution-level interconnections. Under the proposed rule, the transmission-level customer would pay interconnection costs in advance until their forecasted load materializes, at which

point the costs would be collected through rates. Due to the industry-wide implications, CalCCA has taken up this case that 3CE had initially spearheaded.

Status
On October 24, CalCCA submitted an Opening Brief in PG&E’s Rule 30 application advocating for permanent information-sharing requirements to ensure that CCAs receive timely notice of Rule 30 applications in their service areas, to enable the CCA to work with the customer and maximize the potential for efficient procurement. CalCCA’s Opening Brief opposes additional conditions that PG&E has sought that would slow the exchange of information and reduce customer optionality, including adoption of a new non-disclosure agreement to replace existing agreements, Privacy Risk Assessment and Third-Party Cyber-Security Reviews, and an expedited timeline for customers to provide notice of their choice of generation service provider.

Next Steps
3CE and CalCCA will continue to monitor this proceeding to ensure data transparency and equitable customer treatment are upheld throughout the development of the full Rule 30 framework. Reply briefs are due November 24.

Improvements to the Climate Credit – R.25-07-013
Issue
The California Cap-and-Trade program requires power plants, fuel providers, and large industrial facilities that emit greenhouse gases (GHGs) to retire allowances to cover their emissions. The sale of these allowances is used to benefit Californian ratepayers by funding the California Climate Credit, a twice-per-year lump-sum bill credit automatically provided to all bundled and unbundled residential electric customers. On July 28, 2025, the Commission initiated a rulemaking to consider ways to improve the effectiveness of the Climate Credit in support of customer affordability. The preliminary scope of the rulemaking includes potential modifications to customer eligibility criteria, distribution timing, and customer outreach related to the Climate Credit.

Status
CalCCA filed Reply Comments on October 13, 2025, supporting recommendations regarding clear, cost-effective, and administratively simple Climate Credit messaging while requesting that all messaging be competitively neutral and developed in a way that does not advantage IOU over CCA customers. The comments, which were written with input from 3CE staff, also rejected SDG&E’s recommendation to consider the Credit’s distribution timing and eligibility in separate phases and supported PG&E’s recommendation to develop a formal process for residential master-meter configurations.

Next Steps
3CE staff will continue participating in the CalCCA working group on the OIR to prepare for the upcoming Prehearing Conference and issuance of the Scoping Ruling, which are both expected in November.

Energy Resources Recovery Account (ERRA) Forecast – A.24-05-009; A.24-05-007 Issue
ERRA forecast applications are filed annually by IOUs to look ahead at energy procurement-related revenue requirements, including the allocation of costs across Power Charge Indifference Adjustment (PCIA) vintages. CCAs participate through CalCCA to ensure: (1) accuracy of forecast account balances,

rates, and cost calculations; (2) proper attribution of PCIA vintage; (3) proposer attribution between bundled and unbundled customers; (4) appropriateness of IOU proposals within the context of an ERRA forecast proceeding.

Status
PG&E 2026 ERRA Forecast - A.25-05-011
PG&E submitted its October Update Testimony on October 15, 2025. The October Update Testimony incorporates the PCIA MPBs that Energy Division published on October 1, 2025. The 2025 Final Market Price Benchmarks (MPBs) and the updated 2026 Forecast MPBs lead to PG&E PCIA vintage rate increases. CalCCA is reviewing PG&E’s October Update Testimony to file Comments on November 5, 2025.

CalCCA filed an Opening Brief in PG&E’s ERRA Forecast case on October 24, 2025. The Brief focused on recommending the CPUC reject PG&E’s proposal for valuing pre-2019 banked RECs used for compliance in 2026 at zero and PG&E’s proposal to adjust its RA counting for the new RA Slice of Day framework. The Brief also includes arguments recommending the Commission approve CalCCA’s Attestation for Rehearing in the PCIA proceeding on retroactive ratemaking and subsequently order PG&E to update its PCIA RA forecast to use the original RA MPB methodology to produce the 2025 Final RA MPB SCE 2026 ERRA Forecast - A.25-05-008
SCE submitted its October Update Testimony on October 15, 2025. The October Update Testimony incorporates the PCIA MPBs that Energy Division published on October 1, 2025. SCE’s proposed PCIA rates in the October Update Testimony increase sharply. CalCCA is reviewing SCE’s October Update Testimony to file a combined Opening Brief and Comments on the October Update on October 29, 2025.

Next Steps
CalCCA is preparing to file comments on the October Update Testimony and Opening Briefs in both 2026 forecast cases.

General Rate Cases — A.24-09-014; A.24-09-014; A.24-03-019 Issue
In four-year cycles, the IOUs submit General Rate Case (GRC) applications for authority to adjust rates and charges for electric and gas service. The CPUC conducts GRCs in two phases, using Phase I to set the total amount each IOU is authorized to collect and Phase 2 to determine the cost allocation and rate schedules for each customer class. All CCAs participate jointly in GRCs through CalCCA to advocate for just and reasonable IOU rate design and transparent customer bill presentment.

PG&E GRC Phase 2 – A.24-09-014
The ALJ issued a Ruling modifying the schedule of PG&E’s GRC Phase 2 and adding a new track to discuss dynamic rate options on October 9, 2025. The Ruling directs PG&E to file two sets of Supplemental Testimony: one for submitting its Errata related to incorrect marginal distribution capacity costs; and one for updating its dynamic rate design to comply with the Demand Flexibility D.25-08-049.

Next Steps
The PG&E GRC Phase 2 Ruling directs PG&E to propose a schedule for the dynamic rates track by November 17, 2025.

Demand Flexibility – R.22-07-005
Issue
Launched in 2022, this CPUC proceeding was established to enhance demand flexibility (DF) and grid reliability in California, mitigating costs from grid stress. To promote participation in demand flexibility by both bundled and unbundled customers, the CPUC issued a Decision in 2024 to expand two dynamic rate pilot programs to CCAs. As part of 3CE’s load management standards (LMS) plan and to gain experience with dynamic rates, 3CE elected to participate in PG&E’s expanded pilots to offer hourly flex pricing to agricultural, commercial, or residential customers.

Status
On August 28, 2025, the CPUC adopted a Decision establishing guidelines for IOUs to design demand flexibility rates under the CEC’s Load Management Standards. The adopted Decision closed the proceeding and directed the IOUs to file supplemental testimony regarding final design of their demand flexible rates. 3CE staff participated in a PG&E working group to ensure the design and adopted billing structure does not inhibit a CCAs ability to set their own DF rates.

Next Steps
On September 29, 2025, SDG&E filed an Application for Rehearing on the recently adopted Decision, arguing the Commission improperly adopted overly prescriptive rate design guidance based on an insufficient procedural record. SDG&E asserts that the Decision will result in an application with high implementation costs and limited customer participation. The filing echoes concerns previously raised by other parties in the proceeding, including CalCCA, which emphasized the need for additional time for the IOUs to develop their Demand Flex Rate Proposals. 3CE is closely monitoring the outcome of this rehearing request, as any changes to these rates could affect the statewide Hourly Flex Pricing Pilot in which 3CE participates.

Integrated Energy Policy Report –25-IEPR-03
Issue
The Integrated Energy Policy Report (IEPR) is the California Energy Commission’s (CEC) biannual report, with an update every other year, to forecast energy demand and make other considerations on the State’s energy policies and goals. The IEPR forecast is a key input in the electric system planning and is used by the CPUC to inform procurement obligations for LSEs. The report is developed through a collaborative process where the CEC hosts a series of workshops and solicits stakeholder feedback.

Status
The CEC continuously updates and improves the forecast to meet the state’s evolving energy planning needs. On October 8, 2025, the final 2024 IEPR Update was adopted to include analysis on how data center load was incorporated into the demand forecast and a description of the single managed forecast set for electricity planning. The specific elements of this forecast set will be used for planning and procurement in the California ISO’s Transmission Planning Process and the CPUC’s Integrated Resource Planning and helps determine 3CE’s Resource Adequacy requirements.

Next Steps
As the default providers in their service territories, CCAs are working together to determine how this load should be allocated amongst LSEs to ensure grid reliability while also keeping customer rates affordable. 3CE staff attended a demand analysis working group hosted by the CEC on October 30, 2025 to discuss the load modifier draft results for the 2025 IEPR Forecast.3CE will continue to work closely with CalCCA to advocate on behalf of CCAs and their customers, with the final draft 2025 forecast set to be released later this month and adopted early next year.

Disconnections – R. 18-07-005
Issue
The Commission opened the Disconnections proceeding in 2018 pursuant SB 598 to address disconnection rates across California’s electric and gas investor-owned utilities (IOUs) by adopting policies and rules that reduce disconnections and improve reconnection processes and outcomes for disconnected customers. Phase 1 adopted rules to reduce residential customer disconnections and implemented a program that helps eligible low-income customers pay down utility bill debt called the Arrearage Management Plan (AMP). Phase 2, which began in July 2022, seeks to consider additional solutions for reducing disconnection rates, implement SB 1142, which mandates utilities restore service to disconnected customers who agree to enroll in a payment plan, and considers disconnection protections for customers under extreme weather conditions.

Status
On October 13, in an Administrative Law Judge (ALJ) Ruling, the Commission provided parties the opportunity to comment on a procedural path forward for the Commission’s arrearage related assistance programs that were developed to assist customers in avoiding or paying down their past-due balances, including the Percentage of Income Payment Plan (PIPP) pilot program and the Arrearage Management Plan (AMP), which are administered by the IOUs but feature 3CE customer enrollment.

Following the program’s review from a non-profit research group, the ALJ requested parties address specific questions regarding the recommendations and potential modifications for each program.

Next Steps
CalCCA formed a working group of CCAs including 3CE staff to form a response to the Ruling and submit to the docket by November 14. Comments focus on developing recommendations around improving CCA customer participation in the assistance programs and establishing measures to improve disconnections protections while managing customer arrears. Reply comments are due by December 5, 2025.

Staff Report Item 12
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, Chief Executive Officer
SUBJECT: CEO Report
DATE: November 12, 2025

COMMUNITY ADVISORY COUNCIL REPORT
At its October 1, 2025 meeting, the Community Advisory Council (CAC) received updates on Central Coast Community Energy’s (3CE) recent activities and provided input on agricultural electrification initiatives. Staff reported on highlights from 3CE’s Annual Meeting, including budget approval, new CAC appointments, and policy developments such as the Governor’s signing of the Pathways Bill and the implementation of IOU base service charges.

The CAC reviewed the performance of the Agricultural Electrification Program, which has supported over $4.9 million in all-electric ag equipment purchases but continues to face challenges with participation. Members also discussed plans for upcoming focus group meetings to identify barriers and opportunities for agricultural electrification, consistent with the CAC’s FY 2025–26 Workplan. Finally, staff presented an update on 3CE’s Energy Programs portfolio, noting strong participation growth, over 5,300 MT of GHG reductions achieved year-to-date, and continued expansion of residential, commercial, and agricultural electrification efforts.

DISTRIBUTED ENERGY RESOURCES MANAGEMENT SYSTEM (DERMS) / VIRTUAL POWER PLANT (VPP) On October 24th, 3CE published a Request for Proposals seeking a vendor to provide a DERMS platform and related implementation services. The DERMS will serve as a core platform for 3CE’s VPP and Distributed Energy Resources (DER) pilot programs.

EXTENSION OF 3CE MTR PROCUREMENT ORDER OBLIGATION GRANTED The CPUC approved 3CE’s request to extend the compliance deadline for Long Lead Time (LLT) resources from June 1, 2028, to June 1, 2031. This extension provides 3CE with flexibility to accommodate project development timelines and evolving market conditions, while preserving the long-term value of contracts, particularly those for zero-emitting and long-duration energy storage projects where 3CE was

an early actor. The Commission granted the extension based on 3CE’s demonstrated good-faith efforts to meet the original compliance deadline and the continued expectation that these vital clean energy projects will come online by June 1, 2031.

INTEGRATED RESOURCE PLANNING RULING SETS TIMELINE FOR STATEWIDE PROCUREMENT PLANNING The CPUC issued its 2025 Integrated Resource Planning Scoping Memo, which outlines the schedule and scope for the next statewide planning cycle. Load-Serving Entities, including 3CE, must file their Integrated Resource Plans (IRP) by May 5, 2026. The proceeding also establishes a February 2026 decision date for potential interim reliability procurement. Additionally, beginning December 1, 2025, the CPUC will enforce compliance with prior procurement orders through this new proceeding. The Scoping Memo signals continued coordination on the Reliable Clean Power Procurement Program (RCPPP) and emphasizes development of the next Preferred System Plan portfolio that will guide long-term reliability, decarbonization, and affordability planning statewide.

PCIA UPDATE
The IOUs have filed their fall updates in the Energy Resource Recovery Account (ERRA) Forecast proceedings, establishing the preliminary Power Charge Indifference Adjustment (PCIA) values for 2026.

Through the statewide association CalCCA, California CCAs are reviewing these updates to verify accuracy and ensure that only changes from estimated to actual data are reflected. Any new policy or methodological changes to the forecasted PCIA are considered out of scope at this stage. The final PCIA values will be determined in the CPUC’s December decision, underscoring 3CE’s cautious and data-driven approach to understanding the impact of the CPUC’s decision making on all Californians.

SANTA BARBARA OFFICE SPACE
3CE entered into a 5-year lease agreement for 2,500 square feet of office space at 820 State Street in Santa Barbara. 3CE currently has 3 employees that reside in Santa Barbara and routinely have interested qualified candidates for positions from Santa Barbara. The 820 State Street office location will support future recruitment while also providing a physical local presence in Santa Barbara and supporting our local Boardmembers and community engagement. We anticipate moving into the office by January 1, 2026.

ATTACHMENT(S):

1. 3CE Contracts under $200k

2. Customer Outreach and Engagement Report